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Returns & Value Focused

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

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News Releases


Enerplus announces 2008 first quarter results

May 9, 2008
    TSX: ERF.un
    NYSE: ERF

    CALGARY, May 9 /CNW/ - Enerplus Resources Fund is pleased to announce
that operating and financial results for the first quarter of 2008 are in line
with expectations. Highlights for the quarter are as follows:

    -   On February 13, 2008, Enerplus closed the single largest acquisition
        in our history - the $1.7 billion acquisition of Focus Energy Trust.
        Enerplus now has a production weighting of just over 60% natural gas
        and 40% crude oil and NGLs in its portfolio.

    -   Daily production volumes averaged 89,150 BOE/day reflecting the
        additional volumes from Focus since February 13, 2008. Our
        production volumes in March were approximately 100,000 BOE/day,
        being the first full month including Focus production and an all-
        time high for Enerplus. We continue to expect full year production
        volumes to average 98,000 BOE/day with an exit rate of 100,000
        BOE/day.

    -   Cash flow from operating activities was $256.2 million up 33%
        over the same period last year on the strength of increased
        commodity prices and production volumes.

    -   Cash distributions to unitholders were maintained at $0.42 per unit
        per month ($1.26 per unit for the quarter) with a payout ratio of
        75% versus 82% for the first quarter of 2007 after adjustments for
        working capital. Based on existing commodity prices and current
        distribution levels, we would expect our payout ratio will decrease
        throughout the year.

    -   Our development capital program was one of the most active in our
        history with total spending of approximately $126 million and
        256 gross wells drilled. Over 50% of our development capital was
        invested in oil properties however the majority of the wells drilled
        were in our shallow natural gas resource play which offers a
        significant number of low risk infill drilling locations.

    -   Our cash operating costs averaged $8.88/BOE during the quarter, up
        from $8.53/BOE during the same period last year however we continue
        to maintain our annual guidance of approximately $8.65/BOE.

    -   Cash general and administrative expenses decreased to $1.85/BOE
        compared to $1.94/BOE during the first quarter of 2007.

    -   Our price risk management program generated cash gains of
        $4.3 million on our natural gas contracts and cash losses of
        $15.2 million on our crude oil contracts for a total cost of
        $10.9 million for the quarter versus a gain of $7.9 million for the
        same period in 2007.

    -   We continue to maintain a conservative use of debt as reflected by
        our debt to trailing cash flow ratio of 1.0x.

    SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS

    The financial information presented for the first quarter 2008 includes
the results of Focus Energy Trust from the date of closing February 13, 2008.
    All amounts are stated in Canadian dollars unless otherwise specified. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Where applicable, natural gas has been
converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE
rate is based on an energy equivalent conversion method primarily applicable
at the burner tip and does not represent a value equivalent at the wellhead.
Use of BOE in isolation may be misleading. Certain prior year amounts have
been restated to reflect current year presentation. Readers are also urged to
review the Management's Discussion & Analysis (MD&A) and Audited Financial
Statements for more fulsome disclosure on our operations. These reports can be
found on our website at www.enerplus.com, our SEDAR profile at www.sedar.com
and as part of our SEC filings available on www.sec.gov.

    SELECTED FINANCIAL RESULTS

    For the three months ended March 31,                  2008          2007
    -------------------------------------------------------------------------
    Financial (000's)
      Cash Flow from Operating Activities          $   256,216   $   193,181
      Cash Distributions to Unitholders(1)             192,358       157,671
      Cash Withheld for Acquisitions and Capital
       Expenditures                                     63,858        35,510
      Net Income                                       121,394       107,873
      Debt Outstanding (net of cash)                 1,097,821       716,860
      Development Capital Spending                     126,262       109,952
      Acquisitions                                   1,765,069        63,423
      Divestments                                        2,122             -

    Actual Cash Distributions paid to Unitholders  $      1.26   $      1.26

    Financial per Weighted Average Trust Units(2)
      Cash Flow from Operating Activities          $      1.74   $      1.57
      Cash Distributions per Unit(1)                      1.30          1.28
      Cash Withheld for Acquisitions and Capital
       Expenditures                                       0.44          0.29
      Net Income                                          0.82          0.88
      Payout Ratio(3)                                      75%           82%

    Selected Financial Results per BOE(4)
      Oil & Gas Sales(5)                           $     62.10   $     49.08
      Royalties                                         (11.57)        (9.24)
      Commodity Derivative Instruments                   (1.35)         1.01
      Operating Costs                                    (8.96)        (8.55)
      General and Administrative                         (1.85)        (1.94)
      Interest and Other Income and Foreign
       Exchange                                          (0.84)        (1.32)
      Taxes                                              (1.18)        (0.26)
      Restoration and Abandonment                        (0.50)        (0.42)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash working capital           $     35.85   $     28.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average Number of Trust Units
     Outstanding Including Equivalent Exchangeable
     Partnership Units (thousands)                     147,482       123,282
    Debt/Trailing 12 Month Cash Flow Ratio(6)             1.0x          0.8x
    -------------------------------------------------------------------------

    SELECTED OPERATING RESULTS

    For the three months ended March 31,                  2008          2007
    -------------------------------------------------------------------------
    Average Daily Production
      Natural gas (Mcf/day)                            307,746       275,714
      Crude oil (bbls/day)                              33,256        35,567
      NGLs (bbls/day)                                    4,603         4,509
      Total (BOE/day)                                   89,150        86,028

      % Natural gas                                        58%           53%

    Average Selling Price(5)
      Natural gas (per Mcf)                        $      7.52   $      7.21
      Crude oil (per bbl)                                86.02         57.26
      NGLs (per bbl)                                     69.75         44.09
      US$ exchange rate                                   1.00          0.85

    Net Wells drilled                                      125            40
    Success Rate                                          100%           98%
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        per unit may not correspond to the actual cash distributions to
        unitholders of $1.26 as a result of using the weighted average trust
        units outstanding for the period.
    (2) Based on weighted average trust units outstanding for the period,
        including the exchangeable partnership units assumed through the
        Focus Energy Trust acquisition.
    (3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
        from Operating Activities.
    (4) Non-cash amounts have been excluded.
    (5) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (6) Including the trailing 12 month cash flow of Focus Energy Trust.



    TRUST UNIT TRADING SUMMARY                    TSX - ERF.un    NYSE - ERF
    for the three months ended March 31, 2008        (CDN$)         (US$)
    -------------------------------------------------------------------------

    High                                           $     44.75   $     44.31
    Low                                            $     34.02   $     32.59
    Close                                          $     44.65   $     43.40


    2008 CASH DISTRIBUTIONS PER TRUST UNIT            CDN$           US$
    -------------------------------------------------------------------------
    Production Month      Payment Month

    January               March                    $      0.42   $      0.41
    February              April                           0.42          0.42
    March                 May                             0.42        0.41(*)
    -------------------------------------------------------------------------
    First Quarter Total                            $      1.26   $      1.24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Calculated using an Canadian/US$ exchange rate of 1.02



    2008 PRODUCTION AND DEVELOPMENT ACTIVITY

    As at March 31, 2008      Production     Capital       Wells Drilled(*)
                                 Volumes    Spending     --------------------
    Play Type                   (BOE/day) ($millions)      Gross         Net
    -------------------------------------------------------------------------

    Shallow Gas & CBM             20,627      $ 22.4         149        92.0
    Crude Oil Waterfloods         14,784        17.2          22        10.5
    Deep Tight Gas                11,937        22.9          28         4.0
    Bakken Oil                    10,878        19.6           4         3.1
    Other Conventional
     Oil & Gas                    30,924        22.7          53        15.2
    -------------------------------------------------------------------------
    Total Conventional            89,150      $104.8         256       124.8

    Oil Sands
    Kirby                              -        20.6           -           -
    Joslyn                             -          .7           -           -
    Laricina                           -          .2           -           -
    -------------------------------------------------------------------------
    Total Oil Sands                    -      $ 21.5           -           -

    Total                         89,150      $126.3         256       124.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Drilling totals to do not include the delineation wells drilled
        during the quarter at Kirby

    Success Rate To Date: 100%

    OPERATIONS UPDATE

    Our Canadian drilling program employed as many as 17 drilling rigs and 20
service rigs in our operations including those dedicated to our Kirby
delineation program throughout the quarter. Our U.S. operations also had 2
drilling rigs and 6 - 7 service rigs in use through the quarter. While modest
savings were realized on day rates for drilling rigs, labour, steel and
service costs have not abated.
    With the recent strengthening in natural gas prices and the additional
working interests in the Shackleton property acquired from Focus, we have
increased our activities in our shallow gas resource play. During the quarter,
Enerplus drilled almost 150 shallow gas wells, the majority of which were in
the Countess and Verger area taking the well density to 16 wells per section.
At Shackleton, a total of 41 Milk River natural gas wells were drilled during
the quarter (including Enerplus and Focus activity) and booster compression
was installed in the Miry Bay area. In addition, a total of 24 existing wells
were recompleted to add reserves and production from the Milk River interval
as well.
    At Tommy Lakes, the winter drilling program was completed with a total of
17 wells successfully drilled, completed and tied-in before spring break up
with results in line with expectations. This was slightly more than originally
planned by Focus.
    Our crude oil development activities continue to benefit from the current
strength in oil prices. Although the number of wells drilled is significantly
less than in the shallow natural gas arena, the cost and productivity per well
is considerably higher. Our conventional oil activities were focused at
Routledge and Shorncliffe in Southeast Saskatchewan and our waterfloods at
Pembina, Alberta and Virden, Manitoba.
    Development activity in our Bakken resource play kept two drilling rigs
active for most of the quarter drilling four additional third wells per
section. We temporarily slowed our refrac program to concentrate on higher
return optimization activities and expect to resume the refrac program in
June. Through our current activities in the U.S., we expect to maintain
production volumes in the range of 11,000 BOE/day throughout 2008 with
targeted spending of $55 to $65 million. We continue to advance our
development plans beyond 2008 and have identified opportunities which will
help to maintain production in the coming years. We also continue to pursue
growth opportunities in the U.S. which are outside of our existing areas.

    UPDATE ON KIRBY OIL SANDS PROJECT

    Development plans at our Kirby oil sands project continued throughout the
first quarter with the execution of our winter delineation program. We drilled
55 core holes and 3 water source/disposal wells on the lease. Our preliminary
review of the core hole samples is encouraging. We expect to use this new
information in support of the initial development on this lease, a
10,000 bbl/day steam assisted gravity drainage ("SAGD") project, and will
provide updated resources estimates for the lease once we have fully evaluated
the results of this program. We continue to expect to file our regulatory
application for the 10,000 bbl/day project in late fall of this year and will
provide new capital estimates associated with the project as part of the
application.
    We are pleased to report that we have been successful in attracting
experienced and talented personnel to our oil sands resource team over the
past quarter and now have over 20 people dedicated exclusively to the Kirby
oil sands project. Combined, we have over 130 years of oil sands experience
and over 350 years of industry experience within the team including direct
experience from most of the active SAGD projects in western Canada.

    Strategic Review of Joslyn Lease

    On March 25, 2008, we announced that we were commencing a review of
strategic options regarding our 15% working interest in the Joslyn oil sands
lease ("Joslyn"). Joslyn is located in the Athabasca oil sands fairway in
northeastern Alberta and consists of both mining and SAGD development
projects. Our oil sands portfolio is comprised of three principal investments:
a 100% working interest in the operated Kirby SAGD project a 15% non-operated
working interest in the Joslyn mining and SAGD project; and a 12% equity
investment and minor joint venture participation with Laricina Energy Ltd.,
("Laricina") a private oil sands company pursuing SAGD projects in Alberta.
    A strategic review of our portfolio of oil sands and conventional
projects has resulted in the decision to consider options to rebalance our
portfolio. Enerplus' low risk, distribution-oriented business model
necessitates a portfolio of assets that provide near-term cash flow, future
growth potential and an appropriate balance of commodities. Managing the
future capital requirements of the portfolio while maintaining financial
flexibility is critical to the long-term success of Enerplus. While we believe
that both Joslyn and Kirby provide attractive long-term potential, the
operated nature of the Kirby project provides enhanced control over the timing
and nature of our capital spending profile. In addition, there are more SAGD
opportunities within Canada for future growth and SAGD is better suited to our
technical competencies and business model.
    Should the strategic review result in a decision to sell all or a portion
of Joslyn, sale proceeds would initially be used to reduce our current bank
debt.

    GREENHOUSE GAS EMISSIONS REGULATIONS

    Enerplus continues to monitor and evaluate the developments associated
with carbon emissions regulations associated with environmental policy and
legislation in all jurisdictions where we operate. In particular, we are
currently reviewing the Government of Canada's "Turning the Corner" plan and
will continue to evolve our strategies and responses to the plan. Draft
regulations under the plan are expected to be published in the latter half of
this year for public comment. Under the proposed plan, the oil and gas
industry will be required to reduce its emissions intensity from 2006 levels
by 18% by 2010 and 2% every following year. The proposed federal regulations
also require oil sands upgraders and in-situ projects to meet certain carbon
capture and storage targets by 2018. Given Enerplus' interest in various oil
sands development areas (Kirby, Joslyn and Laricina), we will be closely
monitoring the development of the proposed federal regulations.
    In January, 2008, the Government of Alberta released its new climate
change strategy. The Alberta strategy focuses on the three areas of carbon
capture and storage, conserving and using energy more efficiently and
"greening" energy production. The provincial government will be providing
updates as to its specific plans for implementation of various portions of its
strategy. Certain climate change regulations came in to effect in Alberta on
July 1, 2007 which set an emissions level of 100,000 tonnes/year to be
considered a "large final emitter" (under Alberta regulations). Enerplus does
not have any operated facilities that meet this level; however, we do
participate in a small number of partner-operated facilities that fall into
this category. We also anticipate that our proposed Kirby project would fit
this classification once operational. We will be evaluating carbon capture and
storage alternatives for our Kirby development as a normal course of business.
    We will be working with government at all levels where we have operations
to assist in the development of regulatory design in an effort to strike a
productive balance between environment responsibility and continued positive
economic impact.

    APPOINTMENT OF NEW U.S. PRESIDENT OF OPERATIONS

    I am also pleased to announce that Mr. Dana Johnson has joined the
Enerplus executive group as the President, U.S. Operations. Mr. Johnson brings
over 25 years of oil and gas industry experience, the majority of which has
been spent in the United States with Quicksilver Resources Inc. and Shell
Exploration and Production Company. His background in both conventional and
unconventional plays throughout Canada and the U.S. will be a tremendous asset
to Enerplus in leading this operating division. Larry Hammond and Ray Daniels
will continue to lead our Canadian conventional and oil sands divisions
respectively.

    THE FUTURE

    While the oil and gas industry faces many challenges we believe there are
also many opportunities in front of us. We continue to be committed to the
long-term success of our business and are focused on improving our operations
to the benefit of our unitholders. We believe that our unitholders have
invested in Enerplus because of their desire for income. We plan to manage our
business in order to provide that income today, tomorrow and beyond 2010 when
the Canadian federal income trust tax is implemented. We will look to maximize
our cash flow and provide an attractive yield to our investors through the
effective use of our tax pools and our development capital expenditures. Our
current balance sheet strength, the opportunities within our asset base and
our technical expertise positions Enerplus for future success.


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

    The following discussion and analysis of financial results is dated
May 8, 2008 and is to be read in conjunction with:

    -   the audited consolidated financial statements as at and for the years
        ended December 31, 2007 and 2006; and
    -   the unaudited interim consolidated financial statements as at and for
        the three months ended March 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.
    The following MD&A contains forward-looking information and statements.
We refer you to the end of the MD&A for our disclaimer on forward-looking
information and statements.

    NON-GAAP MEASURES

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

    OVERVIEW

    On February 13, 2008 we successfully closed the largest transaction in
our 22 year history, acquiring Focus Energy Trust ("Focus") for total
consideration of $1.7 billion including approximately $357 million of assumed
debt and working capital. The results of the quarter include the results of
Focus from the date of closing. The integration of Focus is progressing well.
The drilling programs at Tommy Lakes and Shackleton are on schedule. We
retained approximately 88% of the Focus staff, excluding executives, and the
offices have been successfully integrated.
    Overall production was in-line with expectations although operating costs
were slightly higher than anticipated due to optimization work in the United
States and pipeline and facility issues on some non-operated Canadian
properties. Our development capital spending in the first quarter of 2008 was
on target as we successfully integrated and completed both the Focus and
Enerplus first quarter development capital spending programs. In total we
spent $126.3 million and drilled 125 net wells with a 100% success rate.
    Cash flow from operating activities increased 33% to $256.2 million in
the first quarter of 2008 compared to the same period in 2007. The increase
was due to higher realized crude oil and natural gas prices along with
increased production as a result of the Focus acquisition. The higher
commodity prices increased our price risk management program costs as we
incurred cash losses of $10.9 million and non-cash losses of $79.4 million due
to higher forward commodity prices at quarter end.
    We maintained our monthly cash distributions at $0.42 per unit during the
first quarter with a payout ratio of 75% and our debt-to-cash flow remains at
a conservative 1.0x (including both Enerplus' and Focus' trailing twelve month
cash flow).
    We continue to maintain our 2008 guidance targets of $580 million on
development capital spending, operating costs of $8.65/BOE, G&A costs of
$2.20/BOE, annual average production rate of 98,000 BOE/day and an exit
production rate of 100,000 BOE/day.

    RESULTS OF OPERATIONS

    Production

    Production in the first quarter of 2008 was in-line with our expectations
averaging 89,150 BOE/day. March was the first full month of production from
both Enerplus and Focus and the combined production averaged approximately
100,000 BOE/day.
    On November 30, 2007 we experienced a fire at our Giltedge property that
resulted in shut-in production of approximately 2,000 BOE/day that was not
expected to be back on-line until mid-2008. We were able to bring a portion of
the Giltedge production (460 BOE/day) back on-line earlier than expected in
the first quarter of 2008. Successful waterflood activities at our Medicine
Hat Glauconitic C property and optimization activities at our U.S. properties
also resulted in higher than expected production during the quarter.
    These increases were partially offset by lower production of
approximately 200 BOE/day at Bantry North due to regulatory issues at two
non-operated facilities during March. We worked closely with the operator and
regulator and were able to resolve these issues subsequent to the quarter. We
also had unplanned downtime at our non- operated Mitsue property and operated
Chinchaga property resulting in shut-in production of approximately 700
BOE/day for the first quarter, however both Mitsue and Chinchaga were brought
back on-line at the end of March.
    Production volumes in the first quarter of 2008 were 4% higher than the
first quarter of 2007 volumes of 86,028 BOE/day. Incremental production from
the Focus assets beginning February 13, 2008 more than offset the production
interruptions experienced at our Giltedge, Bantry, Mitsue and Chinchaga
properties.
    Average production volumes for the three months ended March 31, 2008 and
2007 are outlined below:

                                                 Three months ended March 31,
    Daily Production Volumes                  2008         2007     % Change
    -------------------------------------------------------------------------
    Natural gas (Mcf/day)                  307,746      275,714          12%
    Crude oil (bbls/day)                    33,256       35,567          (6%)
    Natural gas liquids (bbls/day)           4,603        4,509           2%
    Total daily sales (BOE/day)             89,150       86,028           4%
    -------------------------------------------------------------------------

    Based on the results of our first quarter we continue to expect 2008
annual production volumes to average 98,000 BOE/day and our 2008 exit rate to
be approximately 100,000 BOE/day.

    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 the three months ended March 31, 2008
and 2007. It also compares the benchmark price indices for the same periods.

                                                 Three months ended March 31,
    Average Selling Price(1)                  2008         2007     % Change
    -------------------------------------------------------------------------
    Natural gas (per Mcf)                $    7.52    $    7.21           4%
    Crude oil (per bbl)                      86.02        57.26          50%
    Natural gas liquids (per bbl)            69.75        44.09          58%
    Per BOE                                  62.09        49.08          27%
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments


                                                 Three months ended March 31,
    Average Benchmark Pricing                 2008         2007     % Change
    -------------------------------------------------------------------------
    AECO natural gas - monthly index
     (CDN$/Mcf)                          $    7.13    $    7.46          (4%)
    AECO natural gas - daily index
     (CDN$/Mcf)                               7.90         7.41           7%
    NYMEX natural gas - monthly NX3 index
     (US$/Mcf)                                8.07         6.96          16%
    NYMEX natural gas - monthly NX3 index
     CDN$ equivalent (CDN$/Mcf)               8.07         8.19          (1%)
    WTI crude oil (US$/bbl)                  95.39        58.23          64%
    WTI crude oil: CDN$ equivalent
     (CDN$/bbl)                              95.39        68.51          39%
    US$/CDN$ exchange rate                    1.00         0.85          18%
    -------------------------------------------------------------------------

    Both natural gas and crude oil prices rose significantly during the first
quarter. In the case of natural gas, the winter started off with very weak
natural gas prices and a consensus for mild weather. However, actual weather
was colder than normal across most of North America and imports of LNG to the
U.S. fell considerably year-over-year, resulting in upward pressure on price
throughout the first quarter as storage inventories fell. During the quarter
prices at AECO rose 35% from a low of $6.88/Mcf to a high of $9.32/Mcf.
    We realized an average price on our natural gas of $7.52/Mcf (net of
transportation costs) during the three months ended March 31, 2008, an
increase of 4% from $7.21/Mcf for the same period in 2007. In comparison to
the first quarter of 2007, the AECO monthly index price for natural gas
decreased 4% and the AECO daily index price increased 7%. We sell the majority
of our natural gas under both month and day AECO index contracts. Our realized
natural gas price increase of 4% during the first quarter was comparable to
the average change in the combined indices.
    The West Texas Intermediate ("WTI") crude oil price fell during January
and early February, reaching a low of US$86.99/bbl, but then climbed to a high
of US$110.33/bbl, before settling at US$101.58/bbl on March 31, 2008.
Subsequent to the quarter end, the WTI price has increased a further 15% to
20%. A key driver for the price increase has been demand for commodities,
including crude oil futures, as a hedge against inflation. Fundamentals were
also supportive as global demand continued to grow during the quarter.
    The average price we received for our crude oil during the three months
ended March 31, 2008 increased 50% to $86.02/bbl (net of transportation costs)
from $57.26/bbl during the same period in 2007. In comparison, the WTI crude
oil benchmark price, in Canadian dollars, increased 39% from the corresponding
period in 2007. The relative strength in our sales price increase can be
attributed in large part to the reduced Giltedge heavy crude production. As a
result, heavy crude with its wide differential to WTI comprised a smaller
portion of our overall volumes.
    The Canadian dollar began the year at $0.99 per U.S. dollar, stronger
than par, and fluctuated between $0.97 per U.S. dollar and $1.03 per U.S.
dollar during the quarter. As a result of the Canadian dollar strengthening
throughout 2007, the first quarter of 2008 average exchange rate increased 18%
compared to the same period in 2007. As most of our crude oil and a portion of
our natural gas are priced in reference to U.S. dollar denominated benchmarks,
this movement in the exchange rate reduced the Canadian dollar prices that we
would have otherwise realized.

    Price Risk Management

    We have developed a price risk management framework to respond to the
volatile commodity price environment in a prudent manner. Consideration is
given to our overall financial position together with the economics of our
development capital program and acquisitions. Consideration is also given to
the upfront costs of our risk management program as we seek to limit our
exposure to price downturns while maintaining participation should commodity
prices increase. Hedge positions for any given term are transacted across a
range of prices and time. With respect to our natural gas and crude oil hedges
for 2008, our overall hedge position was influenced both by existing Focus
hedges and by the objective to protect the downside and assure cash flow
certainty during the first year of this significant acquisition.
    Given the above framework and objectives, we entered into additional
commodity contracts during the first quarter of 2008. Considering all
financial contracts transacted as of April 28, 2008, we have protected a
portion of our natural gas price risk through to October 31, 2009 and a
portion of our crude oil price risk through to December 31, 2009. We also have
protected our exposure to rising electricity costs for some of our consumption
in the Alberta power market through to December 31, 2009. See Note 9 for a
list of our current price risk management positions.
    The following is a summary of the financial contracts in place at
April 28, 2008, including positions entered into by Focus, expressed as a
percentage of our forecasted net production volumes:

                                                     Natural Gas
                                                      (CDN$/Mcf)
    -------------------------------------------------------------------------
                                           April 1,  November 1,     April 1,
                                            2008 -       2008 -       2009 -
                                        October 31,    March 31,  October 31,
                                              2008         2009         2009
    -------------------------------------------------------------------------
    Floor Prices (puts)                    $  7.09      $  8.66            -
      % (net of royalties)                     25%          14%            -

    Fixed Price (swaps)                    $  7.44      $  9.35         $7.86
      % (net of royalties)                     20%           3%           1%

    Capped Price (calls)                   $  8.25      $ 11.24            -
      % (net of royalties)                     25%          11%            -
    -------------------------------------------------------------------------

                                                       Crude Oil
                                                       (US$/bbl)
    -------------------------------------------------------------------------
                                           April 1,      July 1,   January 1,
                                            2008 -       2008 -       2009 -
                                           June 30, December 31, December 31,
                                              2008         2008         2009
    -------------------------------------------------------------------------
    Floor Prices (puts)                    $ 71.43      $ 72.09      $ 81.36
      % (net of royalties)                     38%          35%          16%

    Fixed Price (swaps)                    $ 79.95      $ 79.97     $ 100.05
      % (net of royalties)                     18%          19%           2%

    Capped Price (calls)                   $ 85.09      $ 85.48     $  92.98
      % (net of royalties)                     24%          22%          12%
    -------------------------------------------------------------------------

    Based on weighted average price (before premiums), estimated average
annual production of 98,000 BOE/day, and assuming for 2008 a 19% royalty rate.
For 2009 we have assumed a 24% royalty rate reflecting the increased royalties
for Alberta production at the current forward commodity price levels.

    Accounting for Price Risk Management

    During the first quarter of 2008 our price risk management program
generated cash gains of $4.3 million on our natural gas contracts and cash
losses of $15.2 million on our crude oil contracts. The natural gas cash gains
are due to contracts in place that provided floor protection that was above
market prices. The crude oil cash losses are the result of crude oil prices
rising above our swap and sold call positions. In comparison, our first
quarter of 2007 commodity price risk management program resulted in cash
losses of $0.5 million on our natural gas contracts and cash gains of
$8.4 million on our crude oil contracts.
    At March 31, 2008 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represent losses of $50.2 million and
$77.9 million, respectively. The loss positions at March 31, 2008, which are
due to forward natural gas and crude oil prices being above our sold call and
swap positions, are recorded as current deferred financial credits on our
balance sheet. In comparison, at December 31, 2007 the fair value of our
natural gas and crude oil derivative instruments represented a gain of $9.7
million and a loss of $52.5 million respectively. Upon the closing of the
Focus acquisition the fair value loss, included with the Focus assets, on both
the natural gas derivative instruments of $1.6 million and crude oil
derivative instruments of $4.3 million were recorded on our balance sheet. The
change in the fair value of our derivative instruments during the quarter
resulted in unrealized losses of $58.3 million for natural gas and
$21.1 million for crude oil. As the forward markets for natural gas and crude
oil fluctuate and new contracts are executed and existing contracts are
realized, changes in fair value are reflected as a non-cash charge or non-cash
gain in earnings. See Note 9 for details.
    The following table summarizes the effects of our financial contracts on
income.

    Risk Management Gains/
     (Losses)
    ($ millions, except per     Three months ended        Three months ended
     unit amounts)                  March 31, 2008            March 31, 2007
    -------------------------------------------------------------------------
    Cash (losses)/gains:
      Natural Gas              $4.3      $0.15/Mcf      $(0.5)   $(0.02)/Mcf
      Crude Oil               (15.2)    (5.03)/bbl        8.4       2.63/bbl
                             -------                   -------
    Total Cash (losses)/
     gains                   $(10.9)   $(1.35)/BOE       $7.9      $1.01/BOE

    Non-cash losses on
     financial contracts:
      Change in fair value
       - natural gas         $(58.3)   $(2.08)/Mcf     $(20.6)   $(0.83)/Mcf
      Change in fair value
       - crude oil            (21.1)    (6.98)/bbl      (12.9)   (4.02)/bbl
                             -------                   -------
    Total non-cash losses    $(79.4)   $(9.79)/BOE     $(33.5)   $(4.32)/BOE

                             -------                   -------
    Total losses             $(90.3)  $(11.14)/BOE     $(25.6)   $(3.31)/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash Flow Sensitivity

    The sensitivities below reflect the impact on cash flow per trust unit
for the remaining three quarters of 2008 and include the commodity contracts
described in Note 9 as well as the impact of 2008 forward market prices as at
April 21, 2008. To the extent the market price of crude oil and natural gas
change significantly from the April 21, 2008 levels, the sensitivities will no
longer be relevant as the effect of our commodity contracts will change.

    Sensitivity Table                               Estimated Effect on 2008
                                                  Cash Flow per Trust Unit(1)
    -------------------------------------------------------------------------
    Change of $0.15 per Mcf in the price
     of AECO natural gas                                     $0.06
    Change of US$1.00 per barrel in
     the price of WTI crude oil                              $0.04
    Change of 1,000 BOE/day in production                    $0.10
    Change of $0.01 in the US$/CDN$ exchange rate            $0.10
    Change of 1% in interest rate                            $0.05
    -------------------------------------------------------------------------
    (1) Assumes constant working capital and 160,147,000 units outstanding.
        The impact of a change in one factor may be compounded or offset by
        changes in other factors. This table does not consider the impact of
        any inter-relationship among the factors.

    Revenues

    Crude oil and natural gas revenues for the three months ended March 31,
2008 were $503.7 million ($510.0 million, net of $6.3 million of
transportation costs), an increase of 33% or $123.7 million compared to
$380.0 million ($385.9 million, net of $5.9 million of transportation costs)
in the first quarter 2007. Increased gas production as a result of the Focus
acquisition and substantially higher crude oil prices were the primary reasons
for the higher revenues.

    Analysis of Sales              Crude                 Natural
     Revenue(1) ($ millions)         oil        NGLs         Gas       Total
    -------------------------------------------------------------------------
    Quarter ended March 31, 2007  $183.3      $ 17.9      $178.8      $380.0
    Price variance(1)               87.0        10.7        12.4       110.1
    Volume variance                (10.0)        0.6        23.0        13.6
    -------------------------------------------------------------------------
    Quarter ended March 31, 2008  $260.3      $ 29.2      $214.2      $503.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.

    Other Income

    Other income for the three months ended March 31, 2008 was $15.1 million
compared to $14.2 million for the three months ended March 31, 2007. During
the first quarter of 2008 we realized a gain of $8.3 million on the sale of
certain marketable securities, as well as interim payments for our business
interruption insurance of $6.4 million related to the Giltedge fire. During
the first quarter of 2007 we realized a gain of $14.1 million on the sale of
certain marketable securities.

    Royalties

    Royalties are paid to various government entities and other land and
mineral rights owners. For the three months ended March 31, 2008 and 2007
royalties were $93.8 million and $71.6 million respectively, approximately 19%
of oil and gas sales, net of transportation costs. Overall, royalties
increased primarily as a result of additional revenue from higher oil prices
and the additional Focus assets acquired.
    In October 2007, the Alberta government announced a 'New Royalty
Framework' ("NRF") which will be effective January 1, 2009. In the context of
an annualized 2008 forward market outlook of $110.00/bbl crude oil and
$9.00/Mcf natural gas, and relative to Enerplus' current properties and
production profile in Alberta, we estimate the incremental annual impact of
the NRF to be approximately $90 to $100 million.
    In April 2008, the Alberta government announced some changes to the NRF
to encourage the development of deep, high-cost oil and gas reserves. These
programs will be implemented on January 1, 2009 along with the NRF. These new
programs are not expected to have a significant effect on our 2008 capital
plans. Had these new programs been in place during 2007, approximately
23 gross (5 net) of Enerplus' natural gas wells drilled in 2007 would have
qualified for potential royalty credits totaling $0.8 million. Our crude oil
wells would not have been affected.
    We continue to expect royalties to be approximately 19% of oil and gas
sales, net of transportation costs for 2008. In 2009 given current commodity
prices, we estimate the average royalty rate for the Fund including all
royalties will be approximately 24% of oil and gas sales, net of
transportation costs.
    As at the date of this MD&A the Alberta government had not yet made the
necessary legislative and administration changes to implement the NRF. The NRF
announcement can be found on the Alberta government's website at
www.gov.ab.ca.

    Operating Expenses

    Operating expenses for the three months ended March 31, 2008 were
$8.88/BOE or $72.0 million, compared to $8.53/BOE or $66.0 million for the
same period in 2007. Excluding the non-cash gain included in operating
expenses related to our electricity swaps, operating costs were $8.96/BOE
compared to $8.55/BOE for the same period in 2007. We had higher operating
costs at our Mitsue and Chinchaga properties due to costs associated with
pipeline and facility issues along with additional optimization expenses onour
U.S. properties. Partially offsetting these increases was the addition of
lower operating cost properties from Focus beginning February 13, 2008.
    We are maintaining our annual guidance for operating costs of
approximately $8.65/BOE.

    General and Administrative Expenses ("G&A")

    During the first quarter of 2008 G&A expenses decreased 8% to $2.03/BOE
or $16.4 million compared to $2.21/BOE or $17.1 million for the first quarter
of 2007. Total cash G&A was relatively unchanged year-over-year, with higher
overall salary and benefits costs offset by lower long term cash compensation
charges which are impacted by our trust unit price.
    During the quarter our G&A expenses included non-cash charges for our
trust unit rights incentive plan of $1.5 million or $0.18/BOE compared to
$2.1 million or $0.27/BOE for 2007. These amounts relate solely to our trust
unit rights incentive plan and are determined using a binomial lattice option-
pricing model. See Note 8 for further details.
    The following table summarizes the cash and non-cash expenses recorded in
G&A:

    General and Administrative Costs             Three months ended March 31,
    ($ millions)                                          2008          2007
    -------------------------------------------------------------------------
    Cash                                           $      14.9   $      15.0
    Trust unit rights incentive plan (non-cash)            1.5           2.1
    -------------------------------------------------------------------------
    Total G&A                                      $      16.4   $      17.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (Per BOE)                                             2008          2007
    -------------------------------------------------------------------------
    Cash                                           $      1.85   $      1.94
    Trust unit rights incentive plan (non-cash)           0.18          0.27
    -------------------------------------------------------------------------
    Total G&A                                      $      2.03   $      2.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    We are maintaining our guidance for G&A expenses at $2.20/BOE, which
includes 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
(see Note 6).
    Interest on long-term debt for the three months ended March 31, 2008
totaled $13.3 million, a $3.6 million increase from $9.7 million during the
comparable quarter of 2007. The increase was due to higher average
indebtedness partially offset by a lower weighted average interest rate of
4.3% during the first three months of 2008 compared to 4.9% in the same period
in 2007.
    The following table summarizes the cash and non-cash interest expense
recorded.

    Interest Expense                             Three months ended March 31,
    ($ millions)                                          2008          2007
    -------------------------------------------------------------------------
    Interest on long-term debt                     $      13.3   $       9.7
    Unrealized gain                                       (6.3)         (1.6)
    -------------------------------------------------------------------------
    Total Interest Expense                         $       7.0   $       8.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    At March 31, 2008 approximately 12% of our debt was based on fixed
interest rates while 88% had floating interest rates. In comparison, at
March 31, 2007 approximately 19% of our debt was based on fixed interest rates
and 81% was floating. The increased percentage of floating rate debt is due to
the bank debt that was assumed with the Focus acquisition.

    Capital Expenditures

    During the first quarter of 2008 we spent $126.3 million on development
capital and facilities, an increase of $16.3 million or 15% compared to the
same period in 2007. The increase was largely due to the successful completion
of Focus' original development capital program and drilling an additional two
wells at Tommy Lakes. Our development capital program is expected to remain on
target through the remainder of the year. To date we have achieved a 100%
success rate with our drilling program on 125 net wells.
    Property acquisitions during the three months ended March 31, 2008 were
$7.5 million compared to $63.4 million during the three months ended March 31,
2007 which related primarily to the acquisition of gross-overriding royalty
interests in the Jonah natural gas field in Wyoming. Our corporate acquisition
of Focus closed during the quarter for consideration of approximately
$1.7 billion. Refer to Note 4 for further details.
    Total net capital expenditures of approximately $1.9 billion for the
first quarter of 2008 compared to $174.8 million for the first quarter of 2007
are outlined below.

                                                 Three months ended March 31,
    Capital Expenditures ($ millions)                     2008          2007
    -------------------------------------------------------------------------
    Development expenditures                         $   109.3   $      90.8
    Plant and facilities                                  17.0          19.2
    -------------------------------------------------------------------------
      Development Capital                                126.3         110.0
    Office                                                 1.6           1.4
    -------------------------------------------------------------------------
      Sub-total                                          127.9         111.4
    Acquisitions of oil and gas properties(1)              7.5          63.4
    Corporate Acquisitions                             1,757.5             -
    Dispositions of oil and gas properties(1)             (2.1)            -
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                   $ 1,890.8   $     174.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total Capital Expenditures financed with
     cash flow                                       $    63.9   $      35.5
    Total Capital Expenditures financed with
     debt and equity                                   1,826.9         139.3
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                   $ 1,890.8   $     174.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of post-closing adjustments.

    We are maintaining our 2008 guidance of $580 million for annual
development capital spending.

    Oil Sands

    Our Joslyn and Kirby development projects have not commenced commercial
production. As a result all associated costs inclusive of acquisition
expenditures, development capital spending, salaries and benefits, engineering
and planning, net of revenues generated, are capitalized and excluded from our
depletion calculation.
    During the first quarter of 2008 we capitalized costs of $0.7 million
related to Joslyn as we continued to build the steam chambers in producing
wells and bring two wells back on production that had workovers completed at
year end. At our Kirby project we capitalized approximately $20.6 million and
were successful in completing our core hole drilling program drilling 55 core
holes and 3 water source/disposal wells. At March 31, 2008 capitalized costs
life-to-date for Joslyn were $117.1 million and for Kirby were $226.0 million
for a combined total of $343.1 million.
    On March 25, 2008 we announced that we are commencing a review of
strategic options regarding our 15% working interest in Joslyn. A review of
our portfolio of oil sands and conventional projects has resulted in the
decision to consider options to rebalance the portfolio. Our distribution-
oriented business model necessitates a portfolio of assets that provide near-
term cash flow, future growth potential and an appropriate balance of
commodities. While we believe that both Joslyn and Kirby provide attractive
long-term potential, the operated nature of the Kirby project provides
enhanced control over the timing and nature of our capital spending profile.
Should the review result in a decision to sell all or a portion of Joslyn,
sale proceeds would initially be used to reduce our outstanding bank debt.
Given our conservative balance sheet, such sale proceeds would reinforce our
borrowing capacity, enhance our ability to fund future capital spending and
acquisition activity and minimize the need for future equity.

    Depletion, Depreciation, Amortization and Accretion ("DDA&A")

    DDA&A of property, plant and equipment ("PP&E") is recognized using the
unit-of-production method based on proved reserves.
    For the three months ended March 31, 2008 DDA&A increased to
$139.8 million or $17.23/BOE compared to $119.1 million or $15.38/BOE during
the same period in 2007. The increase is primarily due to additional PP&E and
production as a result of the Focus acquisition.
    No impairment of the Fund's assets existed at March 31, 2008 using year-
end reserves updated for acquisitions, divestitures and management's estimates
of future prices.

    Asset Retirement Obligations

    In connection with our operations, we anticipate we will incur
abandonment and reclamation costs for surface leases, wells, facilities and
pipelines. Total future asset retirement obligations are 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 approximately $204.3 million at March 31, 2008
compared to $165.7 million at December 31, 2007. The increase of $38.6 million
relates primarily to the acquisition of Focus. See Note 3.
    The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation and asset retirement
obligations settled during the period.

                                                 Three months ended March 31,
    ($ millions)                                          2008          2007
    -------------------------------------------------------------------------
    Amortization of the asset retirement cost        $     4.7   $       3.4
    Accretion of the asset retirement obligation           2.5           1.7
    -------------------------------------------------------------------------
    Total Amortization and Accretion                 $     7.2   $       5.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Asset Retirement Obligations Settled             $     4.0   $       3.3
    -------------------------------------------------------------------------

    The timing of actual asset retirement costs will differ from the timing
of amortization and accretion charges. Actual asset retirement costs will be
incurred over the next 66 years with the majority between 2038 and 2047. For
accounting purposes, the asset retirement cost is amortized using a unit-of-
production method based on proved reserves before royalties while the asset
retirement obligation accretes until the time the obligation is settled.

    Taxes

    Future Income Taxes

    Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
    Our future income tax recovery was $35.2 million for the quarter ended
March 31, 2008 compared to a recovery of $23.7 million for the same period in
2007. Approximately $10.7 million of the additional recovery is attributed to
Focus and another $2.8 million relates to a British Columbia corporate income
tax rate reduction which became effective during the quarter.

    Current Income Taxes

    In our current structure, payments are made between the operating
entities and the Fund which ultimately transfers both the income and future
tax liability to our unitholders. As a result, no cash income taxes have been
paid by our Canadian operating entities, however an income tax liability of
$24.3 million was triggered on the acquisition of Focus on February 13, 2008.
This liability was included in Focus's assumed working capital and was paid in
April 2008. We expect to recover these taxes over the next twelve months and
as such we have recorded a cash income tax recovery of $2.7 million in first
quarter of 2008.
    The amount of current taxes recorded throughout the year on our U.S.
operations is dependent upon income levels and the timing of both capital
expenditures and the repatriation of funds to Canada. For the three months
ended March 31, 2008 our U.S. operations incurred taxes (income and
withholding) in the amount of $12.2 million compared to $2.0 million for the
same period in 2007. The increase in current taxes was due to an increase in
net income combined with a decrease in capital expenditures during the
quarter.
    We have increased our guidance by 5% for 2008 as we now expect our U.S.
current income and withholding taxes to average approximately 25% of cash flow
from U.S. operations. This guidance is based on current commodity prices, our
current development capital program and assumes all funds in excess of U.S.
development capital spending are repatriated to Canada.
    Effective January 1, 2011 we will be subject to the Specified Investment
Flow-Through ("SIFT") tax should we remain a trust. The Federal budget on
February 26, 2008 proposed that for 2009 tax years and later the SIFT tax will
be based on the general provincial corporate income tax rate in each province
in which the SIFT has a permanent establishment. These proposals would result
in a SIFT being taxed on the same basis as a corporation.

    Net Income

    Net income for the first quarter of 2008 was $121.4 million or $0.82 per
trust unit compared to $107.9 million or $0.88 per trust unit in the same
period for 2007. The $13.5 million increase in net income was primarily due to
an increase in oil and gas sales of $124.2 million and an increase in future
income tax recovery of $11.4 million offset by increased risk management costs
of $64.8 million, increased royalties of $22.3 million and increased DDA&A of
$20.7 million.

    Cash Flow from Operating Activities

    Cash flow for the three months ended March 31, 2008 was $256.2 million or
$1.74 per trust unit compared to $193.2 million or $1.57 per trust unit for
the same period in 2007. The increase in cash flow per unit is largely due to
realizing a higher weighted average sales price on our crude oil and natural
gas sales combined with an increase in production, offset by higher cash risk
management costs, royalties and operating costs.

    Selected Financial Results

                           Three months ended             Three months ended
                               March 31, 2008                 March 31, 2007
                  -----------------------------------------------------------
                                 Non-                          Non-
    Per BOE of    Operating   Cash &           Operating    Cash &
     production        Cash    Other                Cash     Other
     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
    -------------------------------------------------------------------------
    Production per day                  89,150                        86,028
    -------------------------------------------------------------------------
    Weighted
     average
     sales
     price(2)      $ 62.10   $     -   $ 62.10   $ 49.08   $     -   $ 49.08
    Royalties       (11.57)        -    (11.57)    (9.12)        -     (9.12)
    Commodity
     derivative
     instruments     (1.35)    (9.79)   (11.14)     1.01     (4.32)    (3.31)
    Operating costs  (8.96)     0.08     (8.88)    (8.55)     0.02     (8.53)
    General and
     administrative  (1.85)    (0.18)    (2.03)    (1.94)    (0.27)    (2.21)
    Interest
     expense, net
     of interest
     and other
     income          (0.79)     0.77      (.02)    (1.25)     0.21     (1.04)
    Foreign
     exchange
     gain/(loss)     (0.05)    (0.39)    (0.44)    (0.07)     0.01     (0.06)
    Capital taxes        -         -         -     (0.12)        -     (0.12)
    Current income
     tax             (1.18)        -     (1.18)    (0.26)        -     (0.26)
    Restoration and
     abandonment
     cash costs      (0.50)     0.50         -     (0.42)     0.42         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (17.23)   (17.23)        -    (15.38)   (15.38)
    Future income
     tax recovery        -      4.33      4.33         -      3.06      3.06
    Gain on sale of
     marketable
     securities(3)       -      1.02      1.02         -      1.82      1.82
    -------------------------------------------------------------------------
    Total per BOE  $ 35.85   $(20.89)  $ 14.96   $ 28.36   $(14.43)  $ 13.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Cash Flow from Operating Activities before changes in non-cash
        working capital.
    (2) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (3) Gain on sale of marketable securities was a cash item however it is
        included in cash flow from investing activities not cash flow from
        operating activities.



    Selected Canadian and U.S. Results

    The following table provides a geographical analysis of key operating and
financial results for the three months ended March 31, 2008 and 2007.


    (CDN$ millions,         Three months ended            Three months ended
     except per               March 31, 2008                March 31, 2007
     unit amounts)  Canada       U.S.    Total    Canada       U.S.    Total
    -------------------------------------------------------------------------
    Daily
     Production
     Volumes
      Natural gas
       (Mcf/day)   295,799    11,947   307,746   266,050     9,664   275,714
      Crude oil
       (bbls/day)   23,734     9,522    33,256    25,330    10,237    35,567
      Natural gas
       liquids
       (bbls/day)    4,603         -     4,603     4,509         -     4,509
      Total Daily
       Sales
       (BOE/day)    77,637    11,513    89,150    74,180    11,848    86,028

    Pricing(1)
      Natural gas
       (per Mcf)    $ 7.47    $ 8.95    $ 7.52    $ 7.21    $ 7.29    $ 7.21
      Crude oil
       (per bbl)     84.31     90.30     86.02     54.94     62.99     57.26
      Natural gas
       liquids
       (per bbl)     69.75         -     69.75     44.09         -     44.09

    Capital
     Expenditures
      Development
       capital and
       office       $108.3    $ 19.6    $127.9    $ 73.6    $ 37.8    $111.4
      Acquisitions
       of oil
       and gas
       properties      7.4       0.1       7.5       2.1      61.3      63.4
      Dispositions
       of oil
       and gas
       properties     (2.1)        -      (2.1)        -         -         -

    Revenues
      Oil and gas
       sales(1)     $415.7    $ 88.0    $503.7    $315.6    $ 64.4    $380.0
      Royalties(2)   (75.2) (18.6)       (93.8)    (58.9)    (12.7)    (71.6)
      Financial
       contracts     (90.3)        -     (90.3)    (25.6)        -     (25.6)

    Expenses
      Operating     $ 68.6    $  3.4    $ 72.0    $ 63.9    $  2.1    $ 66.0
      General and
       adminis-
       trative        15.1       1.3      16.4      14.8       2.3      17.1
      Depletion,
       depreciation,
       amortization
       and
       accretion     118.4      21.4     139.8      91.5      27.6     119.1
      Current income
       taxes
       (recovery)/
       expense        (2.7)     12.2       9.5         -       2.0       2.0
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) U.S. Royalties include state production tax.

    Quarterly Financial Information

    Oil and gas sales for the first quarter of 2008 increased over the fourth
quarter of 2007 as crude oil and natural gas prices began to increase. Overall
oil and gas sales were lower in 2007 from 2006 as a result of softening
natural gas prices throughout 2006 and remained lower during 2007 as a result
of lower production.
    Net income has been affected by fluctuating commodity prices and risk
management costs, the strengthening Canadian dollar, higher operating and G&A
costs, changes in future tax provisions as well as changes to accounting
policies adopted during 2007. Furthermore, changes in the fair value of all
our financial derivative instruments (commodity, interest and foreign
exchange) are impacted by future prices causing net income to fluctuate
between quarters.

    Quarterly Financial Information

    ($ millions,                                    Net Income per trust unit
     except per trust        Oil and Gas            -------------------------
     unit amounts)             Sales(1)   Net Income      Basic     Diluted
    -------------------------------------------------------------------------
    2008
    First quarter              $   503.7   $   121.4   $    0.82   $    0.82
    -------------------------------------------------------------------------
    2007
    Fourth Quarter             $   389.8   $    98.7   $    0.76   $    0.76
    Third Quarter                  364.8        93.0        0.72        0.72
    Second Quarter                 382.5        40.1        0.31        0.31
    First quarter                  380.0       107.9        0.88        0.87
    -------------------------------------------------
    Total                      $ 1,517.1   $   339.7   $    2.66   $    2.66
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    2006
    Fourth Quarter             $   369.5   $   110.2   $    0.90   $    0.89
    Third Quarter                  398.0       161.3        1.31        1.31
    Second Quarter                 403.5       146.0        1.19        1.19
    First Quarter                  401.7       127.3        1.08        1.07
    -------------------------------------------------
    Total                      $ 1,572.7   $   544.8   $    4.48   $    4.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.

    Liquidity and Capital Resources

    Sustainability of our Distributions and Asset Base

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

    Distribution Policy

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

    Cash Flow from Operating Activities, Cash Distributions and Payout Ratio

    Cash flow from operating activities and cash distributions are reported
on the Consolidated Statements of Cash Flows. During the first quarter of 2008
cash distributions of $192.4 million were funded entirely through cash flow of
$256.2 million.
    Our payout ratio, which is calculated as cash distributions divided by
cash flow, was 75% for the three months ended March 31, 2008 compared to 82%
for the same period in 2007.
    In aggregate, our 2008 first quarter cash distributions of $192.4 million
and our development capital and office expenditures of $127.9 million totaled
$320.3 million, or approximately 125% of our cash flow of $256.2 million. We
rely on access to capital markets to the extent cash distributions combined
with development capital and office expenditures exceed cash flow. Over the
long term we would expect to support our distributions and capital
expenditures with our cash flow, however we would continue to fund
acquisitions and growth through additional debt and equity. There will be
years when we are investing capital in opportunities that do not immediately
generate cash flow (such as our Joslyn and Kirby oil sands projects) where
this relationship will vary. Despite our 2008 first quarter 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 1.0x at March 31, 2008.
    For the three months ended March 31, 2008, our cash distributions
exceeded our net income by $71.0 million (2007 - $49.8 million). Net income
includes $181.7 million of non-cash items (2007 - $129.0 million) such as
DDA&A, changes in the fair value of our derivative instruments based on
forward markets, and future income taxes that do not reduce or increase our
cash flow from operations. Future income taxes can fluctuate from period to
period as a result of changes in tax rates as well as changes in interest,
royalties and dividends from our operating subsidiaries paid to the Fund. In
addition, other non-cash charges such as DDA&A are not a good proxy for the
cost of maintaining our productive capacity as they are based on the
historical costs of our PP&E and not the fair market value of replacing those
assets within the context of the current environment.
    The level of investment in a given period may not be sufficient to
replace productive capacity given the natural declines associated with oil and
natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.
    The following table compares cash distributions to cash flow and net
income.

                                 Three months ended   Year ended   Year ended
    ($ millions, except                   March 31, December 31, December 31,
     per unit amounts)                        2008         2007         2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities:                         $   256.2    $   868.5    $   863.7
    Cash distributions                       192.4        646.8        614.3
    -------------------------------------------------------------------------
    Excess of cash flow over cash
     distributions                       $    63.8    $   221.7    $   249.4

    Net income                           $   121.4    $   339.7    $   544.8
    Shortfall of net income over
     cash distributions                  $   (71.0)   $  (307.1)   $   (69.5)

    Cash distributions per weighted
     average trust unit                  $    1.30    $    5.07    $    5.05
    Payout ratio(1)                            75%          74%          71%
    -------------------------------------------------------------------------
    (1) Based on cash distributions divided by cash flow from operating
        activities.

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

    Long-Term Debt

    Long-term debt at March 31, 2008 was $1,099.3 million, an increase of
$372.6 million from $726.7 million at December 31, 2007.
    Long-term debt at March 31, 2008 is comprised of $860.9 million of bank
indebtedness, which increased $363.5 million from December 31, 2007 and
$238.4 million of senior unsecured notes. The increase in long-term debt is
mainly due to the $330.9 million of debt that was assumed on the Focus
acquisition along with debt incurred to fund our development capital program.
    Our working capital deficiency, excluding cash, at March 31, 2008
increased $63.3 million to $266.7 million from $203.4 million at December 31,
2007. Excluding current deferred financial assets and credits and the related
current future income taxes, our working capital deficiency increased by
$1.0 million compared to December 31, 2007. The increase in accounts
receivable that is attributable to higher commodity prices and production
levels offset the increase in accounts payable that resulted from higher
capital spending activity and increased distributions payable for units issued
in conjunction with the Focus acquisition.
    We continue to maintain a conservative balance sheet as demonstrated
below:

                                                      March 31,  December 31,
    Financial Leverage and Coverage                       2008          2007
    -------------------------------------------------------------------------
    Long-term debt to trailing cash flow               1.0 x(1)        0.8 x
    Cash flow to interest expense                     19.3 x(1)       25.8 x
    Long-term debt to long-term debt plus equity           22%           22%
    -------------------------------------------------------------------------
    Long-term debt is measured net of cash.
    Cash flow and interest expense are 12-months trailing.

    (1) Includes both Enerplus' and Focus' 12 month trailing cash flows and
        interest expense.

    At March 31, 2008 Enerplus had a $1.4 billion unsecured covenant based
three-year term bank facility ending November 2010, through its wholly-owned
subsidiary EnerMark Inc. We have the ability to extend the facility each year
or repay the entire balance at the end of the three-year term. This bank debt
carries floating interest rates that we expect to range between 55.0 and 110.0
basis points over Bankers' Acceptance rates, depending on Enerplus' ratio of
senior debt to earnings before interest, taxes and non-cash items.
    Payments with respect to the bank facilities, senior unsecured notes and
other third party debt have priority over claims of and future distributions
to the unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At March 31, 2008
we are in compliance with our debt covenants, the most restrictive of which
limits our long-term debt to three times trailing cash flow reflecting
acquisitions on a pro forma basis. Refer to "Debt of Enerplus" in our Annual
Information Form for the year ended December 31, 2007 for a detailed
description of these covenants.
    Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and 2011 and are more fully discussed in Note 5.
    We anticipate that we will continue to have adequate liquidity to fund
planned development capital spending during 2008 through a combination of cash
flow retained by the business and debt, if needed.

    Commitments

    Upon the completion of the Focus acquisition we assumed an office lease
with commitments of $0.9 million a year for 3 years and transportation
contracts resulting in a total commitment of $40.0 million over a variety of
terms the longest of which is 10 years. The Focus natural gas term
transportation contracts comprise of 40 MMcf/day in British Columbia, and
65 MMcf/day in Saskatchewan.

    Trust Unit Information

    We had 164,142,000 trust units outstanding at March 31, 2008. This
includes the 30,150,000 units issued on February 13, 2008 to acquire Focus and
the 9,087,000 exchangeable partnership units outstanding that were assumed
with the Focus acquisition which are convertible at the option of the holder
into 0.425 of an Enerplus trust unit (3,862,000 trust units). This compares to
123,434,000 trust units at March 31, 2007 and 129,813,000 trust units
outstanding at December 31, 2007. Including the exchangeable partnership units
the weighted average basic number of trust units outstanding during the first
quarter of 2008 was 147,482,000 (2007 - 123,282,000). At May 6, 2008 we had
164,420,000 trust units outstanding including the equivalent partnership
units.
    During the three months ended March 31, 2008 317,000 trust units (2007 -
283,000) 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 $11.9 million (2007 -
$13.0 million) of additional equity to the Fund. For further details see
Note 8.

    Canadian and U.S. Taxpayers

    Enerplus estimates that approximately 95% of cash distributions paid to
Canadian unitholders and 90% of cash distributions paid to U.S. unitholders
will be taxable and the remaining 5% and 10% 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.
    For U.S. taxpayers the taxable portion of cash distributions are
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. This
preferential rate of tax for "Qualified Dividends" is set to expire at the end
of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of
Representatives which, if enacted as presented, would make dividends from
Canadian income funds such as Enerplus ineligible for treatment as a
"Qualified Dividend". The dividends would then become a "non-qualified
dividend from a foreign corporation" subject to the normal rates of tax
commencing with dividends received after the date of enactment. The proposed
bill still requires the approval of the House of Representatives, the Senate
and the President prior to it being enacted. Therefore, we are unable to
determine when or even if the bill will become enacted as presented.
    In April 2008, Enerplus estimated its non-resident ownership to be
approximately 65%.

    Greenhouse Gas and Carbon Emissions

    Enerplus continues to monitor and evaluate the developments associated
with carbon emissions regulations associated with environmental policy and
legislations in all jurisdictions where we operate. In particular, we are
currently reviewing the Government of Canada's "Turning the Corner" plan and
will continue to evolve our strategies and responses to the plan. Draft
regulations under the plan are expected to be published in the latter half of
this year for public comment. Under the proposed plan, the oil and gas
industry will be required to reduce its emissions intensity from 2006 levels
by 18% by 2010 and 2% every following year. The proposed federal regulations
also require oil sands upgraders and in-situ projects to meet certain carbon
capture and storage targets by 2018. Given Enerplus' interest in various oil
sands development areas (Kirby, Joslyn and Laricina), we will be closely
monitoring the development of the proposed federal regulations.
    In January, 2008, the Government of Alberta released its new climate
change strategy. The Alberta strategy focuses on the three areas of carbon
capture and storage, conserving and using energy more efficiently and
"greening" energy production. The provincial government will be providing
updates as to its specific plans for implementation of various portions of its
strategy. Certain climate change regulations came in to effect in Alberta on
July 1, 2007 which set an emissions level of 100,000 tonnes/year to be
considered a "large final emitter" (under Alberta regulations). Enerplus does
not have any operated facilities that meet this level; however, we do
participate in a small number of partner-operated facilities that fall into
this category. We also anticipate that our proposed Kirby project would fit
this classification once operational. We will be evaluating carbon capture and
storage alternatives for our Kirby development as a normal course of business.
    We will be working with government at all levels where we have operations
to assist in the development of regulatory design in an effort to strike a
productive balance between environment responsibility and continued positive
economic impact. At this stage, without further clarity and specific details
from the governments of Canada and Alberta, it is very difficult to forecast
the increased costs associated with the proposed greenhouse gas and carbon
capture regulations.

    RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

    Convergence of Canadian GAAP with International Financial Reporting
    Standards

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

    Internal Controls and Procedures

    There were no changes in our internal control over financial reporting
during the quarter ended March 31, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.

    CONSOLIDATED BALANCE SHEETS

                                                      March 31,  December 31,
    (CDN$ thousands) (Unaudited)                          2008          2007
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash                                         $     1,453   $     1,702
      Accounts receivable                              247,675       145,602
      Deferred financial assets (Note 9)                 1,102        10,157
      Future income taxes                               33,284        10,807
      Other current                                      3,807         6,373
    -------------------------------------------------------------------------
                                                       287,321       174,641
    Property, plant and equipment (Note 2)           5,652,942     3,872,818
    Goodwill (Note 4)                                  604,645       195,112
    Other assets (Note 9)                               49,966        60,559
    -------------------------------------------------------------------------

                                                   $ 6,594,874   $ 4,303,130
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable                             $   355,464   $   269,375
      Distributions payable to unitholders              68,939        54,522
      Deferred financial credits (Note 9)              128,145        52,488
    -------------------------------------------------------------------------
                                                       552,548       376,385
    -------------------------------------------------------------------------
    Long-term debt (Note 5)                          1,099,274       726,677
    Deferred financial credits (Note 9)                 77,769        90,090
    Future income taxes                                696,183       304,259
    Asset retirement obligations (Note 3)              204,327       165,719
    -------------------------------------------------------------------------
                                                     2,077,553     1,286,745
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 8)                    5,407,195     4,032,680

    Accumulated deficit                             (1,354,917)   (1,283,953)
    Accumulated other comprehensive income             (87,505)     (108,727)
    -------------------------------------------------------------------------
                                                    (1,442,422)   (1,392,680)
                                                     3,964,773     2,640,000
    -------------------------------------------------------------------------

                                                   $ 6,594,874   $ 4,303,130
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

                                                 Three months ended March 31,
    (CDN$ thousands) (Unaudited)                          2008          2007
    -------------------------------------------------------------------------

    Accumulated income, beginning of period        $ 2,286,927   $ 1,952,960
    Adjustment for adoption of financial
     instruments standards                                   -        (5,724)
    -------------------------------------------------------------------------
    Revised accumulated income, beginning of
     period                                          2,286,927     1,947,236
    Net income                                         121,394       107,873
    -------------------------------------------------------------------------
    Accumulated income, end of period              $ 2,408,321   $ 2,055,109

    Accumulated cash distributions, beginning
     of period                                     $(3,570,880)  $(2,924,045)
    Cash distributions                                (192,358)     (157,671)
    -------------------------------------------------------------------------
    Accumulated cash distributions, end of period  $(3,763,238)  $(3,081,716)

    -------------------------------------------------------------------------
    Accumulated deficit, end of period             $(1,354,917)  $(1,026,607)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

                                                 Three months ended March 31,
    (CDN$ thousands) (Unaudited)                          2008          2007
    -------------------------------------------------------------------------
    Balance, beginning of period                     $(108,727)  $    (8,979)
      Transition adjustments on adoption:
        Cash flow hedges                                     -           660
        Available for sale marketable securities             -        14,252
    Other comprehensive income/(loss)                   21,222       (21,458)
    -------------------------------------------------------------------------
    Balance, end of period                           $ (87,505)  $   (15,525)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF INCOME

    (CDN$ thousands except                       Three months ended March 31,
     per trust unit amounts) (Unaudited)                  2008          2007
    -------------------------------------------------------------------------
    Revenues
      Oil and gas sales                            $   510,069   $   385,871
      Royalties                                        (93,836)      (71,565)
      Commodity derivative instruments (Note 9)        (90,379)      (25,606)
      Other income                                      15,116        14,160
    -------------------------------------------------------------------------
                                                       340,970       302,860
    -------------------------------------------------------------------------
    Expenses
      Operating                                         72,016        66,030
      General and administrative                        16,437        17,110
      Transportation                                     6,317         5,864
      Interest (Note 6)                                  6,988         8,115
      Foreign exchange (Note 7)                          3,684           482
      Depletion, depreciation, amortization and
       accretion                                       139,794       119,091
    -------------------------------------------------------------------------
                                                       245,236       216,692
    -------------------------------------------------------------------------
    Income before taxes                                 95,734        86,168
    Current taxes                                        9,541         2,047
    Future income tax recovery                         (35,201)      (23,752)
    -------------------------------------------------------------------------
    Net Income                                     $   121,394   $   107,873
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per trust unit
      Basic                                        $      0.82   $      0.88
      Diluted                                      $      0.82   $      0.87
    -------------------------------------------------------------------------
    Weighted average number of trust units
     outstanding (thousands)(1)
      Basic                                            147,482       123,282
      Diluted                                          147,583       123,363
    -------------------------------------------------------------------------
    (1) Includes the exchangeable partnership units.



    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                                 Three months ended March 31,
    (CDN$ thousands) (Unaudited)                          2008          2007
    -------------------------------------------------------------------------

    Net income                                     $   121,394   $   107,873
    -------------------------------------------------------------------------

    Other comprehensive income/(loss),
     net of tax:
      Unrealized gain/(loss) on marketable
       securities                                        2,578        (3,156)
      Realized gains on marketable securities
       included in net income                           (6,158)      (11,654)
      Gains and losses on derivatives designated
       as hedges in prior periods included in net
       income                                               74          (204)
    Change in cumulative translation adjustment         24,728        (6,444)
    -------------------------------------------------------------------------
    Other comprehensive income/(loss)                   21,222       (21,458)
    -------------------------------------------------------------------------
    Comprehensive income                           $   142,616   $    86,415
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                 Three months ended March 31,
    (CDN$ thousands) (Unaudited)                          2008          2007
    -------------------------------------------------------------------------
    Operating Activities
    Net income                                     $   121,394   $   107,873
    Non-cash items add/(deduct):
      Depletion, depreciation, amortization
       and accretion                                   139,794       119,091
      Change in fair value of derivative
       instruments (Note 9)                             66,472        34,847
      Unit based compensation (Note 8)                   1,486         2,111
      Foreign exchange on translation of senior
       notes (Note 7)                                    9,233        (2,882)
      Future income tax                                (35,201)      (23,752)
      Amortization of senior notes premium                (153)         (169)
      Reclassification adjustments from AOCI to
       net income                                           92          (204)
    Gain on sale of marketable securities               (8,263)      (14,055)
    Asset retirement obligations settled (Note 3)       (4,020)       (3,314)
    -------------------------------------------------------------------------
                                                       290,834       219,546
    Increase in non-cash operating working capital     (34,618)      (26,365)
    -------------------------------------------------------------------------
    Cash flow from operating activities                256,216       193,181
    -------------------------------------------------------------------------
    Financing Activities
    Issue of trust units, net of issue costs
     (Note 8)                                           11,885        13,020
    Cash distributions to unitholders                 (192,358)     (157,671)
    Increase in bank credit facilities                  32,602       100,342
    Decrease in non-cash financing working capital      14,417         2,369
    -------------------------------------------------------------------------
    Cash flow from financing activities               (133,454)      (41,940)
    -------------------------------------------------------------------------
    Investing Activities
    Capital expenditures                              (127,923)     (111,354)
    Property acquisitions                               (7,549)      (63,423)
    Property dispositions                                2,122             -
    Proceeds on sale of marketable securities           18,320        16,467
    Increase in non-cash investing working capital     (10,418)        6,130
    -------------------------------------------------------------------------
    Cash flow from investing activities               (125,448)     (152,180)
    -------------------------------------------------------------------------
    Effect of exchange rate changes on cash              2,437           909
    -------------------------------------------------------------------------
    Change in cash                                        (249)          (30)
    Cash, beginning of period                            1,702           124
    -------------------------------------------------------------------------
    Cash, end of period                            $     1,453   $        94
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash Flow Information
    Cash income taxes paid                         $     9,002   $     3,241
    Cash interest paid                             $     8,318   $     6,086



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    1.  Summary of Significant Accounting Policies

    The interim consolidated financial statements of Enerplus Resources Fund
    ("Enerplus" or the "Fund") have been prepared by management following the
    same accounting policies and methods of computation as the consolidated
    financial statements for the fiscal year ended December 31, 2007. The
    note disclosure requirements for annual statements provide additional
    disclosure to that required for these interim statements. Accordingly,
    these interim statements should be read in conjunction with the Fund's
    consolidated financial statements for the year ended December 31, 2007.
    With the exception of additional disclosures included in Note 9 regarding
    financial instruments and capital management, the disclosures provided
    below are incremental to those included in the 2007 annual consolidated
    financial statements of the Fund.

    2.  PROPERTY, PLANT AND EQUIPMENT (PP&E)
                                                      March 31,  December 31,
    ($ thousands)                                         2008          2007
    -------------------------------------------------------------------------
    Property, plant and equipment                  $ 8,355,812   $ 6,429,241
    Accumulated depletion, depreciation and
     accretion                                      (2,702,870)   (2,556,423)
    -------------------------------------------------------------------------
    Net property, plant and equipment              $ 5,652,942   $ 3,872,818
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Capitalized development general and administrative ("G&A") expense of
    $4,909,000 (2007 - $4,019,000) is included in PP&E for the three months
    ended March 31, 2008. Excluded from PP&E for the depletion and
    depreciation calculation is $343,073,000 (2007 - $90,678,000) related to
    the Joslyn development project and the Kirby Oil Sands project, both of
    which have not yet commenced commercial production.

    3.  ASSET RETIREMENT OBLIGATIONS

    Following is a reconciliation of the asset retirement obligations:

                                            Three months ended    Year ended
                                                      March 31,  December 31,
    ($ thousands)                                         2008          2007
    -------------------------------------------------------------------------
    Asset retirement obligations, beginning
     of period                                     $   165,719   $   123,619
    Corporate acquisition                               36,784             -
    Changes in estimates                                 1,500        46,000
    Acquisition and development activity                 1,927         6,441
    Dispositions                                          (110)         (756)
    Asset retirement obligations settled                (4,020)      (16,280)
    Accretion expense                                    2,527         6,695
    -------------------------------------------------------------------------
    Asset retirement obligations, end of period    $   204,327   $   165,719
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    4.  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 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 Partnership Unit. Total
    consideration was approximately $1,366,494,000, consisting of 30,149,752
    trust units issued, 9,086,666 exchangeable partnership units assumed
    (convertible into 3,861,833 trust units) and estimated 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
    are 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 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

    5.  LONG-TERM DEBT
                                                      March 31,  December 31,
    ($ thousands)                                         2008          2007
    -------------------------------------------------------------------------
    Bank credit facilities (a)                     $   860,863   $   497,347
    Senior notes (b)
      US$175 million (issued June 19, 2002)            182,904       175,973
      US$54 million (issued October 1, 2003)            55,507        53,357
    -------------------------------------------------------------------------
    Total long-term debt                           $ 1,099,274   $   726,677
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Unsecured Bank Credit Facility

    Enerplus currently has a $1.4 billion unsecured covenant based three year
    term facility. The facility is extendible each year with a bullet payment
    required at the end of the three year term. Various borrowing options are
    available under the facility including prime rate based advances and
    bankers' acceptance loans. This facility carries floating interest rates
    that are expected to range between 55.0 and 110.0 basis points over
    bankers' acceptance rates, depending on Enerplus' ratio of senior debt to
    earnings before interest, taxes and non-cash items. The effective
    interest rate on the facility for the three months ended March 31, 2008
    was 4.3% (March 31, 2007 - 4.9 %).

    (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 and 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 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 CAD/US exchange rate of 1.02 or CAD $55,080,000.

    On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
    and 3865, Enerplus 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 March 31, 2008 the amortized cost of the
    US$175,000,000 senior notes was US$177,940,000.

    6.  INTEREST EXPENSE
                                                 Three months ended March 31,
    ($ thousands)                                         2008          2007
    -------------------------------------------------------------------------
    Realized
      Interest on long-term debt                   $    13,345   $     9,748
    Unrealized
      Gain on cross currency interest rate swap         (8,344)       (1,283)
      Loss on interest rate swaps                        2,140          (181)
      Amortization of the premium on senior
       unsecured notes                                    (153)         (169)
    -------------------------------------------------------------------------
    Interest Expense                               $     6,988   $     8,115
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    7.  FOREIGN EXCHANGE
                                                 Three months ended March 31,
    ($ thousands)                                         2008          2007
    -------------------------------------------------------------------------
    Unrealized foreign exchange loss/(gain) on
     translation of U.S. dollar denominated
     senior notes                                  $     9,233   $    (2,882)
    Unrealized foreign exchange (gain)/loss on
     cross currency interest rate swap                  (4,171)        2,776
    Unrealized foreign exchange (gain)/loss on
     foreign exchange swaps                             (1,946)            -
    Realized foreign exchange loss                         568           588
    -------------------------------------------------------------------------
    Foreign exchange loss                          $     3,684   $       482
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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.

    8.  UNITHOLDERS' CAPITAL

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

                                            Three months ended    Year ended
                                                      March 31,  December 31,
    Unitholders' capital ($ thousands)                    2008          2007
    -------------------------------------------------------------------------
    Trust units                                    $ 5,239,767   $ 4,020,228
    Exchangeable partnership units                     154,551             -
    Contributed surplus                                 12,877        12,452
    -------------------------------------------------------------------------
    Balance, end of period                         $ 5,407,195   $ 4,032,680
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Trust Units

    Authorized: Unlimited number of trust units

                                  Three months ended           Year ended
    (thousands)                     March 31, 2008         December 31, 2007
    Issued:                        Units      Amount       Units      Amount
    -------------------------------------------------------------------------
    Balance, beginning of
     period                      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                 53       1,636         205       6,758
    Trust unit rights
     incentive plan (non-cash)
     - exercised                       -       1,061           -       2,288
    DRIP(*), net of redemptions      264      10,249       1,102      50,053
    Issued for acquisition of
     corporate and property
     interests (non-cash)         30,150   1,206,593       1,105      54,750
    -------------------------------------------------------------------------
                                 160,280 $ 5,239,767     129,813 $ 4,020,228
    Equivalent exchangeable
     partnership units             3,862     154,551           -           -
    -------------------------------------------------------------------------
    Balance, end of period       164,142 $ 5,394,318     129,813 $ 4,020,228
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Distribution Reinvestment and Unit Purchase Plan

    On February 13, 2008 the Fund issued 30,149,752 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.

    (b) Exchangeable Partnership Units

    In conjunction with the Focus acquisition 9,086,666 Focus Exchangeable
    Limited Partnership Units became exchangeable into Enerplus trust units
    at a ratio of 0.425 of an Enerplus trust unit for each Limited
    Partnership unit (3,861,833 trust units). The exchangeable 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 partnership units after January 8, 2017, unless
    certain conditions are met to permit an earlier redemption date. The
    exchangeable partnership units are not listed on any stock exchange and
    are not transferable. The exchangeable partnership units were recorded at
    fair value, based on the 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. The Focus Exchangeable
    Limited Partnership Units have been renamed Enerplus Exchangeable Limited
    Partnership Units.

    No exchangeable partnership units were converted into trust units during
    the period February 13, 2008 to March 31, 2008. As at March 31, 2008, the
    9,086,666 outstanding exchangeable partnership units represent the
    equivalent of 3,861,833 trust units.

                                  Three months ended           Year ended
    (thousands)                     March 31, 2008         December 31, 2007
    Issued:                        Units      Amount       Units      Amount
    -------------------------------------------------------------------------
    Assumed on February 13, 2008   9,087  $  154,551           -  $        -
    Exchanged for trust units          -           -           -           -
    -------------------------------------------------------------------------
    Balance, end of period         9,087  $  154,551           -  $        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (c) Contributed Surplus
                                            Three months ended    Year ended
                                                      March 31,  December 31,
    Contributed surplus ($ thousands)                     2008          2007
    -------------------------------------------------------------------------
    Balance, beginning of period                   $    12,452   $     6,305
    Trust unit rights incentive plan
     (non-cash) - exercised                             (1,061)       (2,288)
    Trust unit rights incentive plan
     (non-cash) - expensed                               1,486         8,435
    -------------------------------------------------------------------------
    Balance, end of period                         $    12,877   $    12,452
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (d) Trust Unit Rights Incentive Plan

    As at March 31, 2008 a total of 4,458,000 rights issued pursuant to the
    Trust Unit Rights Incentive Plan ("Rights Incentive Plan") with an
    average exercise price of $45.77 were outstanding. This represents 2.8%
    of the total trust units outstanding of which 1,544,000 rights, with an
    average exercise price of $44.56, 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 three
    months ended March 31, 2008 reduced the exercise price of the outstanding
    rights by $0.43 per trust unit effective July 2008.

    Activity for the rights issued pursuant to the Rights Plan is as follows:

                                 Three months ended          Year ended
                                    March 31, 2008        December 31, 2007
    -------------------------------------------------------------------------

                                            Weighted                Weighted
                               Number of     Average   Number of     Average
                                  Rights    Exercise      Rights    Exercise
                                  (000's)    Price(1)     (000's)    Price(1)
    -------------------------------------------------------------------------
    Trust unit rights
     outstanding
    Beginning of period            3,404      $47.59       3,079   $   48.53
      Granted                      1,273       42.05         816       48.71
      Exercised                      (53)      31.10        (205)      32.90
      Cancelled                     (166)      48.53        (286)      50.74
    -------------------------------------------------------------------------
    End of period                  4,458      $45.77       3,404   $   47.59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Rights exercisable at
     end of period                 1,544      $44.56       1,635   $   44.84
    -------------------------------------------------------------------------
    (1) Exercise price reflects grant prices less reduction in strike price
        discussed above.

    The Fund uses a binomial lattice option-pricing model to calculate the
    estimated fair value of rights granted under the plan. Non-cash
    compensation costs of $1,486,000 ($0.01 per unit) related to rights
    issued were charged to general and administrative expense during the
    three months ended March 31, 2008 (March 31, 2007 - $2,111,000, $0.02 per
    unit).

    (e) Basic and Diluted per Trust Unit Calculations

    Basic per-unit calculations are calculated using the weighted average
    number of trust units and exchangeable 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 Plan.

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

                                                 Three months ended March 31,
    (thousands)                                             2008        2007
    -------------------------------------------------------------------------
    Weighted average trust units                         145,487     123,282
    Weighted average exchangeable partnership units(1)     1,995           -
    -------------------------------------------------------------------------
    Basic weighted average units outstanding             147,482     123,282
    Dilutive impact of rights                                101          81
    -------------------------------------------------------------------------
    Diluted weighted average units outstanding           147,583     123,363
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on the exchange ratio of 0.425

    (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. Under the plans employees and officers receive
    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 period ended March 31, 2008 the Fund recorded cash compensation
    costs of $1,083,000 ($345,000 period ended March 31, 2007) under the plan
    which are included in general and administrative expenses.

    At March 31, 2008 there were 422,000 performance trust units outstanding.

    9.  Financial Instruments and Risk Management

    (a) Fair Value of Financial Instruments

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

    (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 and are
    reported at amortized cost. At March 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 disposed of certain publicly traded
    marketable securities 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.

    As at March 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. As at March 31, 2008 the Fund reported investments
    in marketable securities of private companies at cost of $49,966,000
    (December 31, 2007 - $45,400,000) in Other Assets on the Consolidated
    Balance Sheet.

    iv.  Accounts Payable & Distributions Payable to Unitholders

    Accounts payable and distributions payable to unitholders are classified
    as other liabilities and are reported at amortized cost. At March 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 amortized cost. At March 31, 2008 the carrying value of the
    bank credit facilities approximated their fair value.

    US$54 million senior notes and US$175 million senior notes

    The US$54,000,000 are classified as other liabilities and reported at
    their amortized cost of US$54,000,000 and are translated into Canadian
    dollars at the period end exchange rate. At March 31, 2008 the Canadian
    dollar amortized cost of the senior notes was approximately $55,507,000
    and the fair value of these notes was approximately $57,657,000.

    US$175 million senior notes

    The US$175,000,000 million senior notes, which are classified as other
    liabilities, are reported at amortized cost of US$177,940,000 and are
    translated to Canadian dollars at the period end exchange rate. At
    March 31, 2008 the Canadian dollar amortized cost of the senior notes was
    approximately $182,904,000 and the fair value of these notes was
    $199,396,000.

    (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 March 31, 2008 a current deferred
    financial asset of $1,102,000, a current deferred financial credit of
    $128,145,000 and a long-term deferred financial credit of $77,769,000 are
    recorded on the consolidated balance sheet.

    The deferred financial credit relating to crude oil instruments of
    $77,919,000 at March 31, 2008 consists of the fair value of the financial
    instruments, representing a loss position of $70,348,000, plus the
    related deferred premiums of $7,571,000. The deferred financial credit
    relating to natural gas instruments of $50,225,000 at March 31, 2008
    consists of the fair value of the financial instruments of $48,179,000
    plus the related deferred premiums of $2,047,000.

    The following table summarizes the fair value as at March 31, 2008 and
    change in fair value for the period ended March 31, 2008 of the Fund's
    derivative financial instruments. The fair values indicated below are
    determined using observable market data including price quotations in
    active markets.

                                             Cross
                                           Currency
                               Interest    Interest    Foreign
                                  Rate        Rate     Exchange  Electricity
    ($ thousands)                Swaps       Swaps      Swaps       Swaps
    -------------------------------------------------------------------------
    Deferred financial
     assets/(credits),
     beginning of period      $     (226) $  (89,439) $     (425) $      450
    Change in fair value
     asset/(credits)           (2,140)(3)   12,515(4)    1,946(5)      652(6)
    -------------------------------------------------------------------------
    Deferred financial
     assets/(credits),
     end of period            $   (2,366) $  (76,924) $    1,521  $    1,102
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Balance sheet
     classification:
    Current asset/(liability)    $     -  $        -  $        -  $    1,102
    Non-current asset/(liability)$(2,366) $  (76,924) $   1,521   $       -
    -------------------------------------------------------------------------

                               Commodity Derivative
                                    Instruments

    ($ thousands)                 Oil        Gas        Total
    -------------------------------------------------------------
    Deferred financial
     assets/(credits),
     beginning of period     $(56,783)(1) $  8,083(2) $ (138,340)
    Change in fair value
     asset/(credits)          (21,136)(7) (58,309)(7)    (66,472)
    -------------------------------------------------------------
    Deferred financial
     assets/(credits),
     end of period            $  (77,919) $  (50,226) $ (204,812)
    -------------------------------------------------------------
    -------------------------------------------------------------

    Balance sheet
     classification:
    Current asset/(liability)    $  (77,919) $(50,226) $(127,043)
    Non-current asset/(liability)$        -  $      -  $ (77,769)
    -------------------------------------------------------------
    (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 $4,171) and interest
        expense (gain of $8,344).
    (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:

                                                 Three months ended March 31,
    ($ thousands)                                           2008        2007
    -------------------------------------------------------------------------
    Loss due to change in fair value                  $   79,445  $   33,482
    Net realized cash losses/(gains)                      10,934      (7,876)
    -------------------------------------------------------------------------
    Commodity derivative instruments loss             $   90,379  $   25,606
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 April 28, 2008 are summarized below.

    Crude Oil:
                                               WTI US$/bbl
                              Daily  ---------------------------------------
                            Volumes      Sold Purchased           Fixed Price
                           bbls/day      Call       Put  Sold Put   and Swaps
    -------------------------------------------------------------------------
    Term
    April 1, 2008
     - June 30, 2008
      Put                     1,500         -    $74.00         -          -
      Swap                    1,000         -         -         -     $92.61
      Swap                      500         -         -         -     $94.30
      Costless Collar(3)        400    $79.00    $70.00         -          -
    April 1, 2008
     - December 31, 2008
      Collar                    750    $77.00    $67.00         -          -
      3-Way option            1,000    $84.00    $66.00    $50.00          -
      3-Way option            1,000    $84.00    $66.00    $52.00          -
      3-Way option            1,000    $86.00    $68.00    $52.00          -
      3-Way option            1,000    $87.50    $70.00    $52.00          -
      3-Way option            1,500    $90.00    $70.00    $60.00          -
      Put Spread              1,500         -    $76.50    $58.00          -
      Put(1)                    700         -    $86.10         -          -
      Swap                      750         -         -         -     $72.94
      Swap                      750         -         -         -     $74.00
      Swap                      750         -         -         -     $73.80
      Swap                      750         -         -         -     $73.35
      Swap(3)                   400         -         -         -     $78.53
    July 1, 2008 -
     December 31, 2008
      Put Spread              1,500         -    $78.00    $58.00          -
      Swap                    1,500         -         -         -     $92.00
      Swap(3)                   400         -         -         -     $84.60
    January 1, 2009 -
     December 31, 2009
      Collar(1)                 850   $100.00    $85.00         -          -
      3-Way option            1,000    $85.00    $70.00    $57.50          -
      3-Way option            1,000    $95.00    $79.00    $62.00          -
      Put Spread(1)             500         -    $92.00    $79.00          -
      Put Spread(2)             500         -    $92.00    $79.00          -
      Swap(1)                   500         -         -         -    $100.05
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the first quarter of 2008.
    (2) Financial contracts entered into subsequent to March 31, 2008.
    (3) Acquired through the acquisition of Focus.

    Natural Gas:
                                                 AECO CDN$/Mcf
                              Daily  ---------------------------------------
                            Volumes      Sold Purchased           Fixed Price
                           MMcf/day      Call       Put  Sold Put   and Swaps
    -------------------------------------------------------------------------
    Term
    April 1, 2008 -
     October 31, 2008
      Collar                    6.6     $8.44     $7.17         -          -
      Collar                    6.6     $7.49     $6.44         -          -
      Collar                    5.7     $7.39     $6.65         -          -
      Collar(1)                11.4     $8.65     $7.60         -          -
      Collar(1)                 2.8     $8.65     $7.49         -          -
      Collar(1)                 2.8     $8.86     $7.91         -          -
      Collar(1)                 2.8     $8.97     $7.91         -          -
      3-Way option              5.7     $9.50     $7.54     $5.28          -
      3-Way option             11.8     $7.91     $6.75     $5.49          -
      3-Way option             11.8     $7.91     $6.75     $5.38          -
      3-Way option(1)           4.7     $8.23     $7.18     $5.28          -
      Swap                      4.7         -         -         -      $8.18
      Swap                      7.6         -         -         -      $6.79
      Swap(3)                  14.2         -         -         -      $6.70
      Swap(1)(3)               14.2         -         -         -      $7.17
      Swap(1)                   2.8         -         -         -      $7.91
      Swap(1)                   2.8         -         -         -      $7.87
      Swap(1)                   2.8         -         -         -      $8.44
      Swap(1)                   2.8         -         -         -      $8.49
      Swap(1)                   5.7         -         -         -      $8.76
    November 1, 2008 -
     March 31, 2009
      Collar(1)                 5.7     $9.50     $8.44         -          -
      3-Way option              5.7    $10.71     $7.91     $5.80          -
      3-Way option(1)           1.9    $10.55     $8.44     $6.33          -
      3-Way option(1)           5.7    $10.71     $8.44     $6.33          -
      3-Way option(1)           9.5    $12.45     $8.97     $7.39          -
      3-Way option(2)           4.7    $12.45     $8.97     $7.39          -
      Put Spread(1)             4.7         -     $8.97     $7.39          -
      Put Spread(2)             4.7         -     $8.97     $7.39          -
      Swap(1)                   2.8         -         -         -      $9.42
      Swap(1)                   2.8         -         -         -      $9.28
      Swap(1)                   2.8         -         -         -      $9.34
    April 1, 2009 -
     October 31, 2009
      Swap(1)                   3.8         -         -         -      $7.86
    2008 - 2010
    Physical
     (escalated pricing)        2.0         -         -         -      $2.59
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the first quarter of 2008.
    (2) Financial contracts entered into subsequent to March 31, 2008.
    (3) Acquired through the acquisition of Focus.

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

                                 Increase/(decrease) to after-tax net income
                              -----------------------------------------------
                                     20% decrease in         20% increase in
    ($ thousands)                     forward prices          forward prices
    -------------------------------------------------------------------------
    Crude oil derivative
     contracts                            $   49,250              $  (64,532)
    Natural gas derivative
     contracts                            $   34,170              $  (42,928)

    Electricity:

    The Fund is subject to electricity price fluctuations and it manages this
    risk by entering into forward fixed rate electricity derivative contracts
    on a portion of its electricity requirements. The Fund's outstanding
    electricity derivative contracts as at April 22, 2008 are summarized
    below.
                                                         Volumes       Price
    Term                                                     MWh    CDN$/MWh
    -------------------------------------------------------------------------
    April 1, 2008 - September 30, 2008                       4.0      $63.00
    April 1, 2008 - December 31, 2009                        4.0      $74.50
    -------------------------------------------------------------------------

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

    Currency Risk
    -------------
    The Fund is exposed to currency risk in relation to its US dollar cash
    balances and US dollar denominated senior unsecured notes. The Fund
    generally maintains a minimal amount of US 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 CAD/US foreign exchange rate
    of 1.02. These foreign exchange swaps mature between October 2011 and
    October 2015 in conjunction with the principal repayments on the
    US$54,000,000 senior notes.

    The following sensitivities show the impact to after-tax net income for
    the period ended March 31, 2008 of the respective changes in the period
    end and applicable forward foreign exchange rates as at March 31, 2008,
    with all other variables held constant:

                                 Increase/(decrease) to after-tax net income
                              -----------------------------------------------
                                     10% decrease in         10% increase in
    ($ thousands)               $CDN relative to $US    $CDN relative to $US
    -------------------------------------------------------------------------
    Translation of senior
     unsecured notes                      $     (7093)            $      7093


                                 Increase/(decrease) to after-tax net income
                              -----------------------------------------------
                                     10% decrease in         10% increase in
    ($ thousands)               $CDN relative to $US    $CDN relative to $US
    -------------------------------------------------------------------------
    Foreign exchange swaps                $      107              $     (107)
    Cross currency interest rate swap(1)  $    6,755              $   (6,755)

    (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 $75,000,000 of notional debt at rates
    varying from 4.10% to 4.61% before banking fees that are expected to
    range between 0.55% and 1.10%. These interest rate swaps mature between
    June 2011 and January 2012.

    If interest rates change by 1%, either lower or higher, on our variable
    rate debt outstanding at March 31, 2008 with all other variables held
    constant, the Fund's after-tax net income for a quarter would change by
    $1,850,000.

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

                                 Increase/(decrease) to after-tax net income
                              -----------------------------------------------
                                     20% decrease in         20% increase in
    ($ thousands)             forward interest rates  forward interest rates
    -------------------------------------------------------------------------
    Interest rate swaps                   $     (332)             $      332
    Cross currency interest rate swap(1)  $    2,701              $   (2,701)

    (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 March 31, 2008 our ten
    largest counterparties, the majority of whom are investment grade,
    represent approximately 70% of our total accounts receivable balance.
    This level of credit concentration is typical of oil and gas companies of
    our size producing in similar regions.

    At March 31, 2008 approximately $11,200,000 or 4.5% 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 March 31, 2008 is
    $2,800,000. The Fund did not provide for any additional doubtful accounts
    nor were any accounts written off during the first quarter.

    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's 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 proportion
    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 March 31, 2008 the debt to cash flow ratio was 1.0x including the 12
    months of trailing cash flow from Focus (March 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 proforma 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:

    -------------------------------------------------------------------------
                        Q1/2008     2007     2006     2005     2004     2003
    -------------------------------------------------------------------------
    Debt-to-Cash
     Flow Ratio             1.0      0.8      0.8      0.8      1.1      0.6
    -------------------------------------------------------------------------

    At March 31, 2008 Enerplus had additional borrowing capacity of
    $539,137,000 under its $1.4 billion bank credit facility. The Fund also
    has the ability to increase the bank credit facility and borrowing
    capacity beyond this level, however increasing the credit facility at
    this time would only result in increased fees. Enerplus does not have any
    subordinated or convertible debt outstanding at this time.

    Capital Spending Plans
    ----------------------
    In 2008 Enerplus expects to spend approximately $580 million developing
    existing assets. A portion of this capital spending is considered
    discretionary. There are limitations to changing the capital spending
    plans during a year. 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 significant 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. In the past, in
    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 the additional funds are available to reduce debt, spend on
    capital development or finance acquisitions. The less cash required to
    finance these activities typically means more cash available for
    distributions and vice versa.

    Enerplus does not forecast distribution levels as it is difficult to
    predict the direction of commodity prices. To the extent possible,
    distributions are set at a level that can be maintained for a sustained
    period. Historical performance has demonstrated that Enerplus investors
    do not reward short-term sporadic increases, nor do they appreciate a
    series of decreases. Enerplus has maintained the current distribution
    level of $0.42/unit for the past 31 consecutive months. A stable or
    growing distribution pattern typically helps support the market price of
    the trust units. This unit price is important as equity is often issued
    in association with large acquisitions and the higher the unit price the
    less dilutive the equity issuance.

    By paying distributions, we effectively earn a tax deduction against the
    corporate taxes in our underlying subsidiaries and pass along 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 creditor's perceptions of the energy sector and Enerplus' credit
    quality. In times of uncertainty, cash flow is preserved as a defense
    against capital market downturns, rather than invested in capital
    programs or increasing distributions.

    Enerplus has recently been successful at increasing its bank credit
    facility from $1 billion to $1.4 billion despite the turmoil in the
    banking sector caused by subprime lending problems. Enerplus currently
    has an NAIC2 rating on the senior unsecured debentures in the U.S.
    private debt markets. In addition, the equity capital markets have
    indicated their continued support. Nonetheless, the capital markets can
    change rapidly with very little notice.

    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.

    Enerplus also routinely disposes of non-core assets, and uses the
    proceeds to repay debt. At the present time, Enerplus is exploring
    strategic alternatives with respect to its Joslyn oil sands lease. If the
    disposition is successful for all or part of the interest in Joslyn, the
    proceeds will be used to repay debt, reinforcing Enerplus' borrowing
    capacity and enhancing the ability to fund future capital spending and
    acquisition activity.

    Liability Maturity Analysis
    ---------------------------
    The following tables detail the principal maturity analysis for the
    Fund's non-derivative financial liabilities at March 31, 2008:

                                               Payments Due by Period
                                          -----------------------------------
    ($ thousands)                  Total        2008        2009        2010
    -------------------------------------------------------------------------
    Accounts Payable          $355,464(1) $  355,464  $        -  $        -
    Distributions payable
     to unitholders             68,939(2)     68,939           -           -
    Bank credit facility         860,863           -           -     860,863
    Senior unsecured notes     323,408(3)          -           -      53,666
    -------------------------------------------------------------------------
    Total commitments         $1,608,674  $  424,403  $        -  $  914,529
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Payments Due by Period       Total
                              -----------------------  Committed
    ($ thousands)                   2011        2012  after 2013
    -------------------------------------------------------------
    Accounts Payable          $        -  $        -  $        -
    Distributions payable
     to unitholders                    -           -           -
    Bank credit facility               -           -           -
    Senior unsecured notes        64,682      64,682     140,378
    -------------------------------------------------------------
    Total commitments         $   64,682  $   64,682  $  140,378
    -------------------------------------------------------------
    -------------------------------------------------------------

    (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).

    It is Enerplus' intention to renew the bank credit facilities before or
    as they come due. Historically, the bank credit facilities have been
    renewed annually, refreshing the associated three year term period.
    Similarly, it is expected that the senior unsecured notes will be
    replaced with replacement notes or bank debt as they become due. Over the
    long-term, Enerplus expects to balance short-term credit requirements
    with bank credit and to look to the term debt markets for longer-term
    credit support.

    ADDITIONAL INFORMATION

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

    For further information, please contact the Investor Relations Department
at Enerplus at 1-800-319-6462 or email investorrelations@enerplus.com.

    Gordon J. Kerr
    President & Chief Executive Officer
    Enerplus Resources Fund

    FORWARD-LOOKING INFORMATION AND STATEMENTS

    This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends",
"strategy" and similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the foregoing,
this news release contains forward-looking information and statements
pertaining to the following: the volumes and estimated value of the Fund's oil
and gas reserves; the life of the Fund's reserves; the volume and product mix
of the Fund's oil and gas production; future oil and natural gas prices and
the Fund's commodity risk management programs; the amount of future asset
retirement obligations; future liquidity and financial capacity; future
results from operations and operating metrics; future costs, expenses and
royalty rates; future interest costs; future development, exploration,
acquisition and development activities (including drilling plans) and related
capital expenditures, including with respect to both our conventional and oil
sands activities and in particular the development of the Kirby and Joslyn
leases; future acquisitions and dispositions; the reinstatement of production
from the Giltedge property and the availability of business interruption
insurance to mitigate the costs of the Giltedge fire; the making and timing of
future regulatory filings and applications; the value of the Fund's equity
investments; future tax treatment of income trusts and future taxes payable by
the Fund; the Fund's tax pools; the impact of the Focus acquisition on the
Fund; the amount, timing and tax treatment of cash distributions to
unitholders; and future payout ratios.
    The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, the implementation of proposed) tax, royalty and
regulatory regimes; the accuracy of the estimates of the Fund's reserve and
resource volumes; certain commodity price and other cost assumptions; the
continued availability of adequate debt and equity financing and cash flow to
fund its plans expenditures; and accurate assessment of the value of Focus'
assets and the extent of its liabilities The Fund believes the material
factors, expectations and assumptions reflected in the forward-looking
information and statements are reasonable but no assurance can be given that
these factors, expectations and assumptions will prove to be correct.
    The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of the Fund's products; unanticipated
operating results or production declines; changes in tax or environmental
laws, royalty rates or other regulatory matters; changes in development plans
the Fund or by third party operators of the Fund's properties, including the
operator of the Joslyn oil sands project; increased debt levels or debt
service requirements; inaccurate estimation of the Fund's and Focus' oil and
gas reserve and resource volumes; limited, unfavourable or a lack of access to
capital markets; increased costs; a lack of adequate insurance coverage;
declines in the value of the Fund's equity investments; the impact of
competitors; and certain other risks detailed from time to time in the Fund's
public disclosure documents (including, without limitation, those risks
identified in this news release and in the Fund's Annual Information Form).
    The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of the Fund
or its subsidiaries assumes any obligation to publicly update or revise them
to reflect new events or circumstances, except as may be required pursuant to
applicable laws.

    %CIK: 0001126874


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