Enerplus announces 2007 second quarter operating and financial results



    TSX: ERF.un
    NYSE:   ERF

    CALGARY, Aug. 2 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our results from operations for the period ending June 30, 2007.
Highlights are as follows:

    

    -   Our activities focused on the successful execution of our capital
        development program, managing our conventional operations and
        advancing our oil sands business. Our balanced portfolio of
        development prospects in Canada and the U.S. continues to benefit us
        by providing flexibility in the allocation of our spending to
        maximize the economic returns of our program. As well, the
        diversification of our production by commodity will also provide
        additional stability in our cash flows as oil prices have stayed
        strong while natural gas prices have recently declined.

    -   Daily production volumes and capital spending are both essentially on
        track with our guidance for the year with production volumes
        averaging 82,478 BOE/day reflecting normal plant maintenance. Year-
        to-date production volumes averaged 84,244 BOE/day and we continue to
        expect we will meet both our average annual and exit rate production
        targets of 85,000 BOE/day and 86,000 BOE/day respectively.

    -   Monthly cash distributions to Unitholders were maintained at
        $0.42 per unit per month, paying a total of $1.26 per unit during the
        quarter with a payout ratio of 68% after working capital.

    -   Wet weather in the month of June throughout western Canada impacted
        our drilling activity during the quarter. We invested approximately
        $80.4 million on both our Canadian and U.S. properties and drilled
        97 gross wells (35.7 net). Year-to-date, we have invested
        approximately $190.4 million through our capital development program
        and we continue to anticipate full year spending of approximately
        $415 million.

    -   Our Canadian conventional capital program continues to provide
        attractive returns from a diverse portfolio of opportunities with
        84 gross wells (28.6 net) drilled during the quarter. Our highest
        concentration of spending was once again at our Sleeping Giant
        property in the U.S. where we invested approximately $33 million and
        drilled 13 gross wells (7.1 net) continuing with our 3rd well per
        section program. With continued strong crude oil prices, the rising
        Canadian dollar and the robust economics surrounding our U.S. capital
        program, we are reallocating a further $10 million from our Canadian
        budget to the Sleeping Giant capital program in 2007 and now expect
        to invest approximately $110 million in the U.S. this year. Drilling
        and related service costs in Canada have decreased since the
        beginning of the year and as a result, we expect to see modest
        savings on our total Canadian development capital program this year.

    -   Increased facility maintenance and costs associated with the
        implementation of training programs to enhance our operational
        efficiencies, combined with lower production volumes, were the main
        drivers in operating costs averaging $9.69 per BOE. Given the
        increases experienced in the first half of the year along with the
        increase in electricity costs expected in the second part of the
        year, we now expect full year operating costs will average
        approximately $9.00 per BOE up from our previous guidance of
        $8.45 per BOE.

    -   We acquired the remaining 10% working interest in the Kirby Oil Sands
        Partnership on June 22, for $20.3 million taking our working interest
        to 100%.

    -   We continue to advance our portfolio of oil sands projects which
        consists of working interests in our operated Kirby SAGD project and
        our non-operated Joslyn project which includes both mining and SAGD
        projects, and our equity investment in Laricina Energy. We have line
        of sight to over 60,000 bbls/day of future oil sands production to
        add to our 85,000 bbls/day of conventional production over the next
        10 years as well as over 460 million barrels of contingent resources
        to potentially add to our 443 million barrels of booked reserves.

    -   Safety performance continued to improve during the quarter with only
        one contractor lost time incident. June marks the eleventh
        consecutive month where no employee has suffered a lost time injury.

    -   Our balance sheet remains one of the strongest in the sector with a
        debt to cash flow ratio of 0.7 times.

    -   Subsequent to the quarter on July 18, Enerplus was included in the
        S&P/TSX 60 Index which is a market weighted index of 60 of the
        largest Canadian public companies. We believe this is beneficial as
        it will provide increased liquidity, visibility and broader
        institutional ownership for Enerplus.
    

    SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS

    All amounts are stated in Canadian dollars unless otherwise specified. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. 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 six months ended June 30,                     2007          2006
    -------------------------------------------------------------------------
    Financial (000's)
      Net Income                                     $ 147,957     $ 273,306
      Cash Flow from Operating Activities              430,663       387,685
      Cash Distributions to Unitholders(1)             320,278       304,593
      Cash Withheld for Acquisitions and
       Capital Expenditures                            110,385        83,092
      Debt Outstanding (net of cash)                   657,945       603,919
      Development Capital Spending                     190,398       236,421
      Acquisitions                                     267,394        42,257
      Divestments                                        5,473        20,806
    Financial per Unit(2)
      Net Income                                     $    1.18     $    2.27
      Cash Flow from Operating Activities                 3.42          3.22
      Cash Distributions to Unitholders(1)                2.54          2.53
      Cash Withheld for Acquisitions and
       Capital Expenditures                               0.88          0.69
      Payout Ratio(3)                                      74%           79%
    Selected Financial Results per BOE(4)
      Oil & Gas Sales(5)                             $   50.00     $   51.88
      Royalties                                          (9.43)       (10.27)
      Commodity Derivative Instruments                    0.45         (2.54)
      Operating Costs                                    (9.16)        (7.94)
      General and Administrative                         (1.93)        (1.64)
      Interest and Foreign Exchange                      (1.34)        (0.91)
      Taxes                                              (0.35)        (0.65)
      Restoration and Abandonment                        (0.48)        (0.36)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash working capital             $   27.76     $   27.57
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Weighted Average Number of Trust Units
     Outstanding (thousands)                           125,849       120,311
    Debt/Trailing 12 Month Cash Flow Ratio                0.7x          0.7x
    -------------------------------------------------------------------------


    SELECTED OPERATING RESULTS

    For the six months ended June 30,                     2007          2006
    -------------------------------------------------------------------------
    Average Daily Production
      Natural gas (Mcf/day)                            270,300       269,922
      Crude oil (bbls/day)                              34,869        36,122
      NGLs (bbls/day)                                    4,325         4,634
      Total (BOE/day) (6:1)                             84,244        85,743

      % Natural gas                                        53%           52%

    Average Selling Price(5)
      Natural gas (per Mcf)                          $    7.13     $    7.27
      Crude oil (per bbl)                            $   59.56     $   62.09
      NGLs (per bbl)                                 $   48.55     $   51.50

      US$ exchange rate                                   0.88          0.88

    Net Wells Drilled                                       75           159
    Success Rate                                           99%          100%
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        to unitholders per unit will not correspond to the actual cumulative
        monthly distributions of $2.52 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.
    (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.


    TRUST UNIT TRADING SUMMARY                    TSX - ERF.un    NYSE - ERF
    for the six months ended June 30, 2007               (CDN$)         (US$)
    -------------------------------------------------------------------------

    High                                                $53.70        $50.75
    Low                                                 $46.50        $39.53
    Close                                               $50.07        $47.08


    2007 CASH DISTRIBUTIONS PER TRUST UNIT                CDN$           US$
    -------------------------------------------------------------------------
    Production Month               Payment Month

    First Quarter Total                                  $1.26         $1.12

    April                          June                  $0.42         $0.39
    May                            July                   0.42          0.40
    June                           August                 0.42        0.39(*)
    -------------------------------------------------------------------------
    Second Quarter Total                                 $1.26         $1.18

    Total Year-to-Date                                   $2.52         $2.30
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Calculated using an exchange rate of 1.07


    2007 Development Activity

                               2nd Quarter               Year to date
                       -------------------------- --------------------------
                          Capital   Wells Drilled    Capital   Wells Drilled
                         Spending  --------------   Spending  --------------
    Play Type          ($millions) Gross      Net ($millions) Gross      Net
    -------------------------------------------------------------------------
    Shallow Gas & CBM      $  6.9   49.0     19.6     $ 10.1   65.0     27.2
    Crude Oil
     Waterfloods              9.8    2.0      2.0       27.0   18.0     15.3
    Bakken Oil               33.1   13.0      7.1       70.9   22.0     13.7
    Oil Sands
     (SAGD/Mining)            9.0      -        -       19.1      -        -
    Other Conventional
     Oil & Gas               21.6   33.0      7.0       63.3   98.0     19.2
    -------------------------------------------------------------------------
    Total                  $ 80.4   97.0     35.7     $190.4  203.0     75.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    

    Oil Sands Activity

    We continue to advance our portfolio of oil sands projects which consists
of working interests in our operated Kirby SAGD project and our non-operated
Joslyn project which includes both mining and SAGD projects, and our equity
investment in Laricina Energy. Our oil sands business is complimentary to our
existing conventional business in western Canada and the U.S. and further
diversifies our portfolio of oil and gas assets. We have line of sight to over
60,000 bbls/day of future oil sands production to add to our 85,000 bbls/day
of conventional production over the next 10 years as well as over 460 million
barrels of contingent resources to potentially add to our 443 million barrels
of booked reserves.
    On April 10, 2007, we completed the acquisition of a 90% working interest
in the Kirby Oil Sands Partnership ("Kirby") located in the heart of the
Athabasca oil sands fairway. On June 22, Enerplus acquired the remaining 10%
working interest in Kirby for $20.3 million and as a result, now owns a 100%
working interest in this operated steam assisted gravity drainage ("SAGD")
project. In aggregate, our Kirby acquisitions represent a total contingent
resource estimate of 244 million barrels. Our development plans for Kirby
include a 10,000 bbl/day SAGD project with first production expected in 2011
and potential expansion to a total of 30,000 to 40,000 bbls/day of bitumen
production. Our plans for this year include a winter core hole drilling
program to further delineate the lease. In addition, preparatory engineering,
stakeholder consultation and other activities are planned that will advance
our regulatory application which we expect to file in 2008.
    Development plans continue to advance on our 15% working interest in the
Joslyn lease. The Operator has contracted Norwest Corporation to conduct a
fulsome mining review of the lease which will be coupled with an internal SAGD
assessment and optimization work expected to be completed in late 2008. The
mining area may be expanded and this could limit the development of SAGD Phase
III which is a 15,000 bbl/day expansion currently planned for production in
2010. Should we convert some of the SAGD area to mining, we could expect to
possibly double the reserve recovery and increase the targeted production from
the mine area.
    Joslyn SAGD Phase II continues to run behind schedule as a result of the
steam release which occurred in May 2006 with current production at
approximately 2,000 bbls/day from 11 well pairs. Three well pairs may be
permanently shut in as a result of the steam release. Of the remaining four
well pairs, steam is being circulated in three and approval is awaited to
start steaming the fourth. Even with best efforts to enhance artificial lift
and operating practices we do not expect to achieve the initial estimate for
peak production of 600 bbls/day per well pair. We are currently assessing
performance and it is too early to determine peak production from the existing
well pairs however, we will require additional well pairs to achieve the
planned 10,000 bbl/day production level.
    The Operator has provided an update on the North mine regulatory
application which confirms our current timing estimates however capital cost
estimates have increased as expected. The Operator is currently expecting
first production in 2013 and peak production of 100,000 bbls/day (15,000
bbls/day net to Enerplus) in 2014 for a total initial capital cost of $2.9
billion ($435 million net to Enerplus) excluding any costs associated with an
upgrader. A design basis memorandum and more rigorous cost estimates are
expected to be completed in 2008.
    We continue to examine our alternatives regarding financing our growing
oil sands business as well as investigating various marketing options for our
future production. We expect to announce these plans as they develop.

    Update on Canadian Tax Legislation

    Bill C-52, which implements the previously announced tax on income
trusts, has passed reading in the House of Commons and the Senate and has now
received Royal Assent. As a result of the tax legislation becoming enacted, we
recorded a non-cash future income tax expense of approximately $78 million
during the quarter. We also filed a material change report on SEDAR and EDGAR
that reflects the changes to the estimated after tax net present value of
future revenues from our oil and gas reserves, and related information, in
accordance with Canadian National Instrument 51-101.
    Additional details of the legislation remain to be clarified and further
tactical decisions will be made over time. However, we intend to maintain our
yield-oriented distribution model given our belief that investor demographics,
the demand for yield product support such a model with a premium valuation.
Our lower risk energy production, long life and low decline assets, and large
scalable resource plays support this approach and are consistent with a
successful oil and gas business. We will continue our disciplined acquisition
strategy as the normal growth parameters outlined in the legislation and the
strength of our balance sheet support active involvement in the M&A market in
the U.S., Canada, and potentially internationally. We see value in the
four-year tax exemption period and would be hesitant to make major changes to
our structure during this period without compelling reasons that we do not
currently foresee. As of December 2006, we had tax pools of approximately $1.9
billion. We expect to preserve and possibly build those pools in the next four
years in order to maximize the tax shelter available post 2010.

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

    The following discussion and analysis of financial results is dated
August 1, 2007 and is to be read in conjunction with:

    
    -   the MD&A and audited consolidated financial statements as at and for
        the years ended December 31, 2006 and 2005; and
    -   the unaudited interim consolidated financial statements as at
        June 30, 2007 and for the three and six months ended June 30, 2007
        and 2006.
    

    All amounts are stated in Canadian dollars unless otherwise specified.
All references to GAAP refer to Canadian generally accepted accounting
principles. All note references relate to the notes included with the
consolidated financial statements. In accordance with Canadian practice
revenues are reported on a gross basis, before deduction of crown and other
royalties, unless otherwise stated. Oil and natural gas reserves and
production are presented on a company interest basis which is not a term
defined or recognized under NI 51-101. Therefore, our company interest
reserves may not be comparable to similar measures presented by other issuers.
Where applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading. Certain prior year amounts have been restated to reflect current
year presentation.
    The following MD&A contains forward-looking information and statements.
We refer you to the end of the MD&A for our disclaimer on forward-looking
statements and information.

    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.

    Update on Canadian Government Announcement on Intention to Tax Trusts

    On June 22, 2007 Bill C-52, which contains legislative provisions to
implement the proposals to tax publicly traded income trusts in Canada, was
passed by the Senate, given Royal Assent and became law. As a result, our
second quarter future income tax provision includes a future income tax
expense of $78.1 million related to this legislation. This non-cash expense
relates to temporary differences between the accounting and tax basis of the
Fund's assets and liabilities and has no immediate impact on cash flow.
    We are currently evaluating alternatives to determine the optimal
structure for our unitholders. However, we see value in the four-year tax
exempt period through 2010 as a distributing entity and would hesitate to make
major structural changes during this period without compelling reasons which
we do not currently foresee.

    Overview

    Strong commodity prices helped deliver solid cash flow of $237.5 million
for the quarter. As we expected, downtime from scheduled facility maintenance
reduced our average daily production to 82,478 BOE/day. Operating costs for
the quarter increased to $9.69/BOE due to lower production as well as
increased field training costs and unexpected repairs and maintenance
expenses. As a result of operating costs experienced to date, along with
anticipated increases in electricity costs, we are increasing our annual
operating cost guidance to approximately $9.00/BOE. On April 10, 2007 we
acquired a 90% interest in the Kirby Oil Sands Partnership ("Kirby") for
consideration of $182.8 million, consisting of $128.1 million in cash and
$54.7 million in equity. In a subsequent transaction on June 22, 2007 we
acquired the remaining 10% interest for cash consideration of $20.3 million
resulting in a total purchase price of $203.1 million. In conjunction with the
acquisition, we closed an equity offering on April 10, 2007 consisting of 4.25
million trust units raising gross proceeds of $210.6 million.

    Results of Operations

    Production

    Production averaged 82,478 BOE/day during the second quarter of 2007, a
decrease of 4% from 86,028 BOE/day during the first quarter of 2007. As
expected, our production volumes were lower during the quarter given normal
maintenance and turn-around activity which occurs during this time of year.
    For the three and six months ended June 30, 2007 production decreased by
4% and 2%, respectively, compared to the same periods in 2006. The majority of
the decrease was due to natural reservoir declines, partially offset by
additional production from our development capital program and our acquisition
of gross-overriding royalty interests in the Jonah natural gas field in
Wyoming ("Jonah") that closed on January 31, 2007.
    Our average production during the second quarter was weighted 54% natural
gas and 46% crude oil and natural gas liquids on a BOE basis. Average
production volumes for the three and six months ended June 30, 2007 and 2006
are outlined below:

    
                            Three months ended          Six months ended
                                  June 30,                  June 30,
    Daily Production                           %                         %
     Volumes                  2007     2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    Natural gas (Mcf/day)  264,946  269,088   (2)%   270,300  269,922     -%
    Crude oil (bbls/day)    34,178   36,388   (6)%    34,869   36,122   (3)%
    Natural gas liquids
     (bbls/day)              4,143    4,856  (15)%     4,325    4,634   (7)%

    Total daily sales
     (BOE/day)              82,478   86,092   (4)%    84,244   85,743   (2)%
    -------------------------------------------------------------------------
    
    Based on our year-to-date results we are maintaining our annual
production estimate of 85,000 BOE/day and 2007 exit rate of 86,000 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 tables
compare our average selling prices and benchmark price indices for the three
and six months ended June 30, 2007 and June 30, 2006.

    
                            Three months ended          Six months ended
                                  June 30,                  June 30,
    Average Selling                            %                         %
     Price(1)                 2007     2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    Natural gas (per Mcf)   $ 7.04   $ 6.22    13%    $ 7.13   $ 7.27   (2)%
    Crude oil (per bbl)     $61.93   $68.80  (10)%    $59.56   $62.09   (4)%
    Natural gas liquids
     (per bbl)              $53.34   $52.33     2%    $48.55   $51.50   (6)%
    Per BOE                 $50.96   $51.50   (1)%    $50.00   $51.88   (4)%
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.


                            Three months ended          Six months ended
                                  June 30,                  June 30,
    Average Benchmark                            %                         %
     Pricing                  2007     2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    AECO natural gas -
     monthly index
     (CDN$/Mcf)             $ 7.37   $ 6.27    18%    $ 7.42   $ 7.77   (5)%
    AECO natural gas -
     daily index (CDN$/Mcf) $ 7.07   $ 6.01    18%    $ 7.23   $ 6.79     6%
    NYMEX natural gas -
     monthly NX3 index
     (US$/Mcf)              $ 7.56   $ 6.82    11%    $ 7.26   $ 7.95   (9)%
    NYMEX natural gas -
     monthly NX3 index
     CDN$ equivalent
     (CDN$/Mcf)             $ 8.31   $ 7.66     8%    $ 8.25   $ 9.03   (9)%
    WTI crude oil
     (US$/bbl)              $65.03   $70.70   (8)%    $61.65   $67.09   (8)%
    WTI crude oil CDN$
     equivalent (CDN$/bbl)  $71.46   $79.44  (10)%    $70.06   $76.24   (8)%
    US$/CDN$ exchange rate    0.91     0.89     2%      0.88     0.88     -%
    -------------------------------------------------------------------------
    

    We realized an average price on our natural gas of $7.04/Mcf (net of
transportation) during the three months ended June 30, 2007 an increase of 13%
from $6.22/Mcf for the same period in 2006.  For the six months ended  June
30, 2007 we realized a 2% decrease in our average price of $7.13/Mcf compared
to the same period in 2006. We sell approximately one third of our natural gas
to aggregators, with the remainder sold under month and day AECO index
contracts and NYMEX monthly index contracts.  Although our realized average
natural gas price fluctuates from month to month, it remains within the range
of the movement of the benchmark indices as the volume of natural gas sold on
each index can vary each month. Overall our 13% increase and 2% decrease for
the three and six months ended June 30, 2007 compared to the same periods in
2006 are within the range of the combined changes experienced by the AECO and
NYMEX indices.
    The average price we received for our crude oil during the three months
ended June 30, 2007 decreased 10% to $61.93/bbl (net of transportation) from
$68.80/bbl during the same period in 2006. Similarly, the West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the US$ exchange rate, also decreased 10% from the corresponding period in
2006. For the six months ended June 30, 2007, relative to the same period in
2006, our crude oil price fell 4%, while the WTI crude oil benchmark price
fell 8%. This difference was largely due to improved pricing differentials
during the first half of 2007 for our sour and heavy crude oil.
    While the Canadian dollar strengthened significantly against the U.S.
dollar during the quarter, the average exchange rate, for both the three and
six month periods in 2007 was only moderately higher than for the comparable
periods in 2006. As most of our crude oil and natural gas is 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.
    The Canadian/U.S. dollar exchange rate at June 30, 2007 was 0.94 which is
one of the highest levels in recent years.  The forward market is forecasting
the exchange rate to approximate par by the end of 2007 with marginal
weakening in 2008. If the current strength in the Canadian dollar persists our
future Canadian dollar revenues realized from our oil and gas production will
be reduced.  We expect every $0.01 change in the Canadian/U.S. dollar exchange
rate to have a $0.10 annualized per trust unit impact on cash flow.


    Price Risk Management

    Natural gas prices fell in the second quarter with rising levels of
inventory, aggressive drilling in the U.S., and increased liquefied natural
gas imports to North America. Although there remains some threat of increased
hurricane activity this summer, unless there is sustained heat in the U.S.,
there is potential for natural gas prices to remain depressed through the
third quarter. With respect to crude oil prices, global demand continues to
remain strong. Demand, combined with lower than expected non-OPEC production
levels and geopolitical uncertainty, contributed to a steady climb in prices
throughout the second quarter.
    We have developed a price risk management framework to respond to the
volatile price environment in a prudent manner. Consideration is given to our
overall financial position together with the economics of our 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.
    Given our price risk management framework, we entered into additional
commodity contracts during the second quarter of 2007. Considering all of the
financial contracts transacted as of July 25, 2007, we have protected a
portion of our natural gas and crude oil sales for the period July 2007
through December 2008. We have also protected a portion of our exposure to
rising electricity costs in the Alberta power market for the period July 2007
through September 2008. See Note 10 for a detailed list of our current price
risk management positions.
    The following is a summary of the physical and financial contracts in
place at July 25, 2007 as a percentage of our forecasted net production
volumes:

    

                              Natural Gas                     Crude Oil
                              (CDN$/Mcf)                      (US$/bbl)
    -------------------------------------------------------------------------
                     July 1,  November 1,    April 1,     July 1,  January 1,
                       2007-       2007-       2008-       2007-       2008-
                     October       March     October    December    December
                    31, 2007    31, 2008    31, 2008    31, 2007    31, 2008
    -------------------------------------------------------------------------
    Floor Protection
     Price (puts)     $ 7.32      $ 8.54      $ 7.54      $68.93      $66.73
      % (net of
       royalties)        32%         11%          3%         33%         12%

    Fixed Price
     (swaps)          $ 7.58      $ 8.81      $ 8.18      $66.24      $73.15
      % (net of
       royalties)        13%          3%          2%          8%          5%

    Upside Capped
     Price (calls)    $ 9.07      $10.97      $ 9.50      $    -      $83.13
      % (net of
       royalties)        28%         11%          3%           -         12%
    -------------------------------------------------------------------------
    

    Based on weighted average price (before premiums), average annual
    production of 85,000 BOE/day and assuming a 19% royalty rate.


    Accounting for Price Risk Management

    During the second quarter of 2007, our commodity price risk management
program generated cash losses of $1.1 million and non-cash gains of
$19.1 million, compared to cash gains of $7.9 million and non-cash losses of
$33.5 million during the first quarter of 2007. The change in cash costs is
primarily due to the increase in the WTI crude oil benchmark price during the
second quarter of 2007. The impact of lower forward natural gas prices on our
natural gas floor protection at the end of the second quarter resulted in a
non-cash gain. This was partially offset by the impact of higher forward crude
oil prices at the end of the second quarter.
    Compared to the second quarter of 2006 our crude oil cash costs decreased
by $15.7 million from $16.0 million and our natural gas cash costs increased
by $0.2 million from $0.6 million. The decrease in crude oil cash costs is the
result of the expiration of contracts that existed during the second quarter
of 2006 that had ceiling prices between US$35.35/bbl and US$45.80/bbl on
4,500 bbls/day.
    At June 30, 2007 the fair value of our commodity derivative instruments,
net of premiums, represents a gain of $9.2 million and is recorded on our
balance sheet as a deferred financial asset. In comparison at March 31, 2007
the fair value of our commodity derivative instruments represented a loss of
$9.9 million and was recorded on our balance sheet as a deferred financial
credit. 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 ($19.1 million during the second quarter of 2007) are reflected as
a non-cash charge or increase to earnings. See Note 3 for details.
    The following table summarizes the effects of our commodity derivative
instruments on income.

    
    Risk Management Costs
    ($ millions, except          Three months ended      Three months ended
     per unit amounts)              June 30, 2007           June 30, 2006
    -------------------------------------------------------------------------
    Cash losses:
      Crude oil                $  0.3    $  0.10/bbl   $ 16.0    $  4.82/bbl
      Natural gas                 0.8    $  0.03/Mcf      0.6    $  0.03/Mcf
                              --------                --------
    Total Cash losses          $  1.1    $  0.15/BOE   $ 16.6    $  2.12/BOE

    Non-cash (gains)/losses:
      Change in fair value
       -financial contracts    $(19.1)   $(2.54)/BOE   $(22.2)   $(2.84)/BOE
      Amortization of
       deferred financial
       assets                       -    $    - /BOE     18.4    $  2.35/BOE

                              --------                --------
    Total Non-cash (gains)     $(19.1)   $(2.54)/BOE   $ (3.8)   $(0.48)/BOE

                              --------                --------
    Total (gains)/ losses      $(18.0)   $(2.39)/BOE   $ 12.8    $  1.64/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Risk Management Costs
    ($ millions, except           Six months ended        Six months ended
     per unit amounts)              June 30, 2007           June 30, 2006
    -------------------------------------------------------------------------
    Cash (gains)/losses:
      Crude oil                $ (8.1)   $(1.28)/bbl   $ 28.9    $  4.41/bbl
      Natural gas                 1.3    $  0.03/Mcf     10.6    $  0.22/Mcf
                              --------                --------
    Total Cash (gains)/losses  $ (6.8)   $(0.45)/BOE   $ 39.5    $  2.54/BOE

    Non-cash (gains)/losses:
      Change in fair value
       -financial contracts    $ 14.4    $  0.95/BOE   $(62.5)   $(4.03)/BOE
      Amortization of deferred
       financial assets             -    $    - /BOE     36.7    $  2.37/BOE

                              --------                --------
    Total Non-cash
     losses/(gains)            $ 14.4      $0.95/BOE   $(25.8)   $(1.66)/BOE

                              --------                --------
    Total losses               $  7.6      $0.50/BOE   $ 13.7    $  0.88/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Revenues

    Crude oil and natural gas revenues during the second quarter of 2007 were
comparable with the first quarter of 2007 as improved crude oil prices offset
the impact of lower production and natural gas prices.
    Crude oil and natural gas revenues for the three months ended June 30,
2007 were $382.5 million ($387.9 million, net of $5.4 million transportation)
compared to $403.5 million ($409.1 million, net of $5.6 million
transportation) for the same period in 2006. For the six months ended June 30,
2007 revenues were $762.5 million ($773.8 million, net of $11.3 million
transportation) compared to $805.2 million ($816.9 million, net of
$11.7 million transportation) during the same period in 2006.
    The decrease in revenues of $21.0 million or 5% for the three months
ended June 30, 2007 compared to the same period in 2006 was due to lower
production and crude oil prices, offset by increased natural gas prices. The
decrease in revenues of $42.7 million or 5% for the six months ended June 30,
2007 compared to the same period in 2006 was due to decreased production along
with slightly lower commodity prices.

    
    The following table summarizes the changes in sales revenue:

    -------------------------------------------------------------------------
    Analysis of Sales Revenue(1)
     ($ millions)                  Crude Oil      NGLs  Natural Gas    Total
    -------------------------------------------------------------------------
    Quarter ended June 30, 2006     $ 227.8    $  23.1    $ 152.6    $ 403.5
    Price variance(1)                 (21.3)       0.4       19.5       (1.4)
    Volume variance                   (13.9)      (3.4)      (2.3)     (19.6)
    -------------------------------------------------------------------------
    Quarter ended June 30, 2007     $ 192.6    $  20.1    $ 169.8    $ 382.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    ($ millions)                   Crude Oil      NGLs  Natural Gas    Total
    -------------------------------------------------------------------------
    Year-to-date ended
     June 30, 2006                  $ 406.0    $  43.2    $ 356.0    $ 805.2
    Price variance(1)                 (16.0)      (2.3)      (7.9)     (26.2)
    Volume variance                   (14.1)      (2.9)       0.5      (16.5)
    -------------------------------------------------------------------------
    Year-to-date ended
     June 30, 2007                  $ 375.9    $  38.0    $ 348.6    $ 762.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    

    Other Income

    Other income for the three and six months ended June 30, 2007 was
$0.3 million and $14.4 million, respectively compared to $0.2 million and
$1.3 million for the same periods in 2006. During the first quarter of 2007 we
sold certain marketable securities which resulted in a gain of $14.1 million.
These marketable securities were historically recorded in other current assets
at a cost of $2.4 million.

    Royalties

    Royalties are paid to various government entities and other land and
mineral rights owners. For the three and six months ended June 30, 2007
royalties were $72.2 million and $143.8 million, respectively, both
approximately 19% of oil and gas sales, net of transportation. For the three
and six months ended June 30, 2006 royalties were $78.0 million and
$159.4 million, approximately 19% and 20% of oil and gas sales, net of
transportation, respectively. Decreases in royalties for the three and six
months ended June 30, 2007 of $5.8 million and $15.6 million, respectively,
compared to the same periods in 2006 were the result of slightly lower,
weighted average commodity prices.
    For 2007 we expect royalties to be approximately 19% of oil and gas
sales, net of transportation costs. The Alberta government is currently
conducting a review of the oil and gas royalty regime which may impact
royalties in the future. Alberta Crown royalties represented approximately 45%
of total royalties incurred during the first half of 2007.

    Operating Expenses

    Operating expenses during the second quarter of 2007 were $9.69/BOE or
14% higher than the first quarter of 2007. This increase was due to lower
production resulting from scheduled maintenance and the incremental
expenditures associated with these turn-around activities.
    Operating expenses for the three months ended June 30, 2007 were
$72.8 million or $9.69/BOE compared to $65.1 million or $8.31/BOE for the
second quarter of 2006. For the six months ended June 30, 2007 operating costs
were $138.8 million or $9.10/BOE compared to $123.3 million or $7.94/BOE for
the same period in 2006. These increases resulted from unexpected incremental
repairs and maintenance, supplies and labour, and well servicing expenses at
our non-operated Mitsue and operated Gleneath and Giltedge areas. A field
training initiative directed at optimizing production and reducing the time
required to bring new wells on stream also contributed to the cost increase.
We expect many of these costs to moderate over the remainder of the year.
    As a result of the costs incurred to date and increased electricity costs
expected in the second half of 2007, we are revising our annual operating cost
guidance from $8.45/BOE to approximately $9.00/BOE.

    General and Administrative Expenses

    General and administrative ("G&A") expenses for the second quarter of
2007 were 3% lower than the first quarter of 2007. G&A expenses for the three
months ended June 30, 2007 were $16.7 million or $2.22/BOE compared to
$14.6 million or $1.86/BOE for the second quarter of 2006. G&A expenses
totaled $33.8 million or $2.21/BOE for the six months ended June 30, 2007
compared to $27.9 million or $1.80/BOE for the same period in 2006. As
expected, G&A increased over the prior year mainly due to overall compensation
costs associated with retaining experienced staff. Costs to date in 2007 are
in line with our expectations.
    For the three and six months ended June 30, 2007 our G&A expenses
included non-cash charges of $2.1 million or $0.28/BOE and $4.2 million or
$0.28/BOE respectively compared to $1.3 million or $0.17/BOE and $2.5 million
or $0.16/BOE for the same periods in 2006. These amounts relate solely to our
trust unit rights incentive plan and are determined using a binomial lattice
option-pricing model. The volatility of our trust unit price combined with the
increased number of rights outstanding associated with additional employees
have increased the non-cash cost of the plan.
    The following table summarizes the cash and non-cash expenses recorded in
G&A:

    
    General and Administrative      Three months ended      Six months ended
     Costs                                 June 30,              June 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash                            $  14.6    $  13.3    $  29.6    $  25.4
    Non-cash trust unit rights
     incentive plan                     2.1        1.3        4.2        2.5
    -------------------------------------------------------------------------
    Total G&A                       $  16.7    $  14.6    $  33.8    $  27.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (Per BOE)
    -------------------------------------------------------------------------
    Cash                            $  1.94    $  1.69    $  1.93    $  1.64
    Non-cash trust unit rights
     incentive plan                    0.28       0.17       0.28       0.16
    -------------------------------------------------------------------------
    Total G&A                       $  2.22    $  1.86    $  2.21    $  1.80
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    We are maintaining our guidance for G&A expenses at $2.40/BOE, including
non-cash G&A costs of approximately $0.30/BOE.

    Interest Expense

    Interest expense in the second quarter of 2007 was $3.7 million or 46%
higher than the first quarter of 2007 due to changes in non-cash charges. The
first quarter of 2007 included a non-cash gain of $1.6 million while the
second quarter of 2007 included a non-cash loss of $2.1 million. These
non-cash amounts result from the mark-to-market change on our interest rate
swaps and the interest component on our cross currency interest rate swap
("CCIRS") as well as the amortization of the premium on our US$175 million
senior unsecured notes. After consideration of these non-cash items, interest
expense for the second quarter of 2007 was comparable to the first quarter of
2007.
    Interest expense increased to $11.8 million for the second quarter of
2007 from $7.1 million during the same period in 2006. Interest expense
increased to $20.0 million for the six months ended June 30, 2007 from
$15.0 million during the same period in 2006. These increases are due to
higher average indebtedness and interest rates during 2007 combined with the
non-cash losses recorded during the three and six months ended June 30, 2007
of $2.1 million and $0.5 million respectively.
    The following table summarizes the cash and non-cash interest expense
recorded.
    
                                    Three months ended      Six months ended
    Interest Expense                       June 30,              June 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash                            $   9.7    $   7.1    $  19.5    $  15.0
    Non-cash                            2.1          -        0.5          -
    -------------------------------------------------------------------------
    Total Interest Expense          $  11.8    $   7.1    $  20.0    $  15.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    At June 30, 2007 20% of our debt was based on fixed interest rates while
80% had floating interest rates.

    Capital Expenditures

    We spent $80.4 million and $190.4 million on development drilling and
facilities for the three and six months ended June 30, 2007, respectively,
compared to $107.7 million and $236.4 million during the same periods in 2006.
We achieved a 100% success rate with our second quarter drilling program as
35.7 net wells were drilled. Year-to-date, 75.4 net wells were drilled
compared to 159 in 2006. Development in 2007 continues to focus primarily on
Sleeping Giant Bakken oil and crude oil waterfloods. Despite the reduction in
the total number of wells drilled in 2007 compared to 2006, our capital
spending is in line with our expectations as the costs associated with
drilling oil wells are higher than those for shallow natural gas.
    Property acquisitions were $204.0 million and $267.4 million for the
three and six months ended June 30, 2007, compared to $12.2 million and
$42.2 million for the same periods in 2006. On April 10, 2007 we acquired the
initial 90% of Kirby for $182.8 million and subsequently on June 22, 2007 we
acquired the remaining 10% of Kirby for $20.3 million. The total combined
consideration for 100% of Kirby amounted to $203.1 million. During the first
quarter of 2007 we acquired Jonah for total consideration of approximately
$61 million.
    Property dispositions were $5.5 million for both the three and six months
ended June 30, 2007 compared to $1.1 million and $20.8 million for the same
periods in 2006. The majority of the $20.8 million divestment in 2006 related
to the sale of a 1% interest in the Joslyn project.

    
    Total net capital expenditures for 2007 and 2006 are outlined below.

                                    Three months ended      Six months ended
    Capital Expenditures                   June 30,              June 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Development expenditures        $  69.4    $  90.3    $ 160.2    $ 188.0
    Plant and facilities               11.0       17.4       30.2       48.4
    -------------------------------------------------------------------------
      Development Capital              80.4      107.7      190.4      236.4
    Office                              1.6        0.5        3.0        1.3
    -------------------------------------------------------------------------
      Sub-total                        82.0      108.2      193.4      237.7
    Acquisitions of oil and gas
     properties(1)                    204.0       12.2      267.4       42.2
    Dispositions of oil and gas
     properties(1)                     (5.5)      (1.1)      (5.5)     (20.8)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures  $ 280.5    $ 119.3    $ 455.3    $ 259.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Capital Expenditures
     financed with cash flow        $  74.9    $  44.1    $ 110.4    $  83.1
    Total Capital Expenditures
     financed with debt and equity    205.6       75.2      344.9      195.5
    Total non-cash consideration
     for 1% sale of Joslyn project        -          -          -      (19.5)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures  $ 280.5    $ 119.3    $ 455.3    $ 259.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of post-closing adjustments.
    

    We are maintaining our 2007 annual guidance of $415 million for
development capital spending and are reallocating $10 million from our
Canadian capital budget to our U.S. Bakken oil property for the second half of
2007.

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

    DDA&A of property, plant and equipment is recognized using the
unit-of-production method based on proved reserves.
    For the three months ended June 30, 2007, DDA&A increased to $15.58/BOE
compared to $15.47/BOE during the corresponding period in 2006. For the six
months ended June 30, 2007 DDA&A increased to $15.48/BOE compared to
$15.00/BOE during the corresponding period in 2006. The increases in DDA&A per
BOE are attributable to the continuing higher cost of capital additions in
recent years combined with a slightly greater share of U.S. production which
has a higher depletion rate per BOE.
    No impairment of the Fund's assets existed at June 30, 2007 using
year-end reserves updated for acquisitions, divestitures, production and
management's estimates of future prices.

    Asset Retirement Obligations

    The following chart compares the amortization of the asset retirement
costs, accretion of the asset retirement obligation, and actual site
restoration costs incurred.
    

                                    Three months ended      Six months ended
                                           June 30,              June 30,
    ($ millions)                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Amortization of the asset
     retirement cost                $   3.3    $   3.1    $   6.7    $   6.1
    Accretion of the asset
     retirement obligation              1.6        1.6        3.3        3.1
    -------------------------------------------------------------------------
    Total Amortization and
     Accretion                      $   4.9    $   4.7    $  10.0    $   9.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Asset Retirement Obligations
     Settled                        $   3.8    $   2.5    $   7.1    $   5.6
    -------------------------------------------------------------------------
    

    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 2036 and 2045. For
accounting purposes, the asset retirement cost is amortized using a
unit-of-production method based on proved reserves before royalties while the
asset retirement obligation accretes until the time the obligation is settled.

    Taxes

    Future Income Taxes

    Future income taxes arise from differences between the accounting and tax
bases of 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.
    For the three months ended June 30, 2007 a future income tax expense of
$71.0 million was recorded in income compared to a recovery of $44.8 million
for the same period in 2006. For the six months ended June 30, 2007 a future
income tax expense of $47.2 million was recorded in income compared to a
future income tax recovery of $46.6 million during the same period in 2006.
The changes in future income taxes for the quarter and year-to-date are
attributed to the following:

    
    -   During the second quarter of 2007, the Federal Government enacted a
        new tax on distributions from publicly traded income trusts and
        limited partnerships (specified investment flow-through entities, or
        "SIFTs"). The 31.5% SIFT tax will be applicable to the Fund effective
        January 1, 2011 provided that, until that time, the Fund complies
        with the "normal growth" guidelines regarding equity capital as
        outlined by the government. This tax rate change results in a future
        income tax expense of $78.1 million being recorded in the second
        quarter of 2007.
    -   During the second quarter of 2007, the Federal Government also
        enacted a decrease in the corporate rate of tax from 19.0% to 18.5%
        effective January 1, 2011. The effect of this rate change is a future
        income tax recovery of $1.2 million recorded in the second quarter of
        2007.
    -   A future income tax recovery of $32.2 million was included in the
        second quarter of 2006 due to a reduction in the federal and
        provincial corporate tax rates enacted in that quarter.
    

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

    Current Income Taxes

    In our current structure, payments are made between the operating
entities and the Fund which ultimately transfers both income and future income
tax liability to our unitholders. As a result, no cash income taxes have been
paid by our Canadian operating entities. However, effective January 1, 2011
Enerplus will be subject to the SIFT tax at a rate of 31.5%.
    For the three and six months ended June 30, 2007 our U.S. operations
incurred current income related taxes in the amounts of $3.2 million and
$5.3 million respectively, compared to $6.1 million and $10.0 million during
the same periods in 2006.
    The amount of current taxes recorded throughout the year is dependant
upon the timing of both capital expenditures and repatriation of the funds to
Canada. We continue to expect current income and withholding taxes to be
approximately 15% of cash flow from U.S. operations in 2007 assuming all funds
available after U.S. development capital spending are repatriated to Canada.


    Net Income

    Net income for the second quarter of 2007 was $40.1 million or $0.31 per
trust unit compared to $146.0 million or $1.19 per trust unit for the second
quarter of 2006. Net income for the six months ended June 30, 2007 was
$148.0 million or $1.18 per trust unit compared to $273.3 million or $2.27 per
trust unit for the same period in 2006. The decrease during the three and six
months ended June 30, 2007 is due to increased future income tax expense as a
result of the enactment of the SIFT tax, lower oil and gas sales and increased
operating and G&A costs, partially offset by lower royalties and reduced
commodity derivative losses.

    Cash Flow from Operating Activities

    Cash flow for the three and six months ended June 30, 2007 was
$237.5 million and $430.7 million respectively, compared to $198.4 million and
$387.7 million for the three and six months ended June 30, 2006. These
increases were primarily a result of movements in non-cash working capital
between the periods.

    
    Selected Financial Results

                        Three months ended            Three months ended
                           June 30, 2007                 June 30, 2006
    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
     production       Cash   & Other     Total      Cash   & Other     Total
     (6:1)          Flow(1)    Items              Flow(1)    Items
    -------------------------------------------------------------------------
    Production per
     day                                82,478                        86,092
    -------------------------------------------------------------------------
    Weighted
     average sales
     price(2)      $ 50.96   $     -   $ 50.96   $ 51.50   $     -   $ 51.50
    Royalties        (9.63)        -     (9.63)    (9.96)        -     (9.96)
    Commodity
     derivative
     instruments     (0.15)     2.54      2.39     (2.12)     0.48     (1.64)
    Operating costs  (9.80)     0.11     (9.69)    (8.31)        -     (8.31)
    General and
     administrative  (1.94)    (0.28)    (2.22)    (1.69)    (0.17)    (1.86)
    Interest
     expense, net
     of interest     (1.25)    (0.29)    (1.54)    (0.88)        -     (0.88)
    Foreign
     exchange
     gain/(loss)     (0.11)     0.64      0.53     (0.05)     0.36      0.31
    Current
     income
     tax             (0.43)        -     (0.43)    (0.78)        -     (0.78)
    Restoration
     and abandon-
     ment cash
     costs           (0.51)     0.51         -     (0.32)     0.32         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (15.58)   (15.58)        -    (15.47)   (15.47)
    Future income
     tax (expense)/
     recovery            -     (9.45)    (9.45)        -      5.73      5.73
    Gain on sale
     of marketable
     securities          -         -         -         -         -         -
    -------------------------------------------------------------------------
    Total per BOE  $ 27.14   $(21.80)  $  5.34   $ 27.39   $ (8.75)  $ 18.64
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.


                         Six months ended              Six months ended
                           June 30, 2007                 June 30, 2006
    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
     production       Cash   & Other     Total      Cash   & Other     Total
     (6:1)          Flow(1)    Items              Flow(1)    Items
    -------------------------------------------------------------------------
    Production
     per day                            84,244                        85,743
    -------------------------------------------------------------------------
    Weighted
     average sales
     price(2)      $ 50.00   $     -   $ 50.00   $ 51.88   $     -   $ 51.88
    Royalties        (9.43)        -     (9.43)   (10.27)        -    (10.27)
    Commodity
     derivative
     instruments      0.45     (0.95)    (0.50)    (2.54)     1.66     (0.88)
    Operating costs  (9.16)     0.06     (9.10)    (7.94)        -     (7.94)
    General and
     administrative  (1.93)    (0.28)    (2.21)    (1.64)    (0.16)    (1.80)
    Interest
     expense,
     net of
     interest        (1.25)    (0.03)    (1.28)    (0.88)        -     (0.88)
    Foreign
     exchange
     gain/
     (loss)          (0.09)     0.32      0.23     (0.03)     0.18      0.15
    Current
     income tax      (0.35)        -     (0.35)    (0.65)        -     (0.65)
    Restoration
     and abandon-
     ment cash
     costs           (0.48)     0.48         -     (0.36)     0.36         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (15.48)   (15.48)        -    (15.00)   (15.00)
    Future income
     tax (expense)/
     recovery            -     (3.10)    (3.10)        -      3.00      3.00
    Gain on sale of
     marketable
     securities (3)      -      0.92      0.92         -         -         -
    -------------------------------------------------------------------------
    Total per BOE  $ 27.76   $(18.06)  $  9.70   $ 27.57   $ (9.96)  $ 17.61
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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. Financial Results

    The following tables provide a geographical analysis of key operating and
financial results for the three and six months ended June 30, 2007 and 2006.


    (CDN$ millions, except                  Three months ended June 30, 2007
     per unit amounts)                          Canada        U.S.     Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    254,122     10,824    264,946
      Crude oil (bbls/day)                      24,563      9,615     34,178
      Natural gas liquids (bbls/day)             4,143          -      4,143
      Total daily sales (BOE/day)               71,059     11,419     82,478

    Pricing(1)
      Natural gas (per Mcf)                    $  7.03    $  7.37    $  7.04
      Crude oil (per bbl)                      $ 59.59    $ 67.94    $ 61.93
      Natural gas liquids (per bbl)            $ 53.34    $     -    $ 53.34

    Capital Expenditures
      Development capital and office           $  49.1    $  32.9    $  82.0
      Acquisitions of oil and gas properties   $ 204.5    $  (0.5)   $ 204.0
      Dispositions of oil and gas properties   $  (5.5)   $     -    $  (5.5)

    Revenues
      Oil and gas sales(1)                     $ 315.8    $  66.7    $ 382.5
      Royalties                                $ (58.9)   $(13.3)(2) $ (72.2)
      Commodity derivative instruments         $  18.0    $     -    $  18.0

    Expenses
      Operating                                $  70.6    $   2.2    $  72.8
      General and administrative               $  14.9    $   1.8    $  16.7
      Depletion, depreciation,
       amortization and accretion              $  89.5    $  27.4    $ 116.9
      Current income taxes                     $     -    $   3.2    $   3.2
    -------------------------------------------------------------------------



    (CDN$ millions, except                  Three months ended June 30, 2006
     per unit amounts)                          Canada        U.S.     Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    263,265      5,823    269,088
      Crude oil (bbls/day)                      25,912     10,476     36,388
      Natural gas liquids (bbls/day)             4,856          -      4,856
      Total daily sales (BOE/day)               74,645     11,447     86,092

    Pricing(1)
      Natural gas (per Mcf)                    $  6.17    $  8.25    $  6.22
      Crude oil (per bbl)                      $ 67.30    $ 72.50    $ 68.80
      Natural gas liquids (per bbl)            $ 52.33    $     -    $ 52.33

    Capital Expenditures
      Development capital and office           $  80.8    $  27.4    $ 108.2
      Acquisitions of oil and gas properties   $  12.2    $     -    $  12.2
      Dispositions of oil and gas properties   $  (1.1)   $     -    $  (1.1)

     Revenues
       Oil and gas sales(1)                    $ 330.0    $  73.5    $ 403.5
       Royalties                               $ (64.1)   $(13.9)(2) $ (78.0)
       Commodity derivative instruments        $ (12.8)   $     -    $ (12.8)

     Expenses
       Operating                               $  63.4    $   1.7    $  65.1
       General and administrative              $  13.2    $   1.4    $  14.6
       Depletion, depreciation,
        amortization and accretion             $  92.4    $  28.8    $ 121.2
       Current income taxes                    $     -    $   6.1    $   6.1
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.


                                              Six months ended June 30, 2007
    (CDN$ millions, except per unit amounts)    Canada        U.S.     Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    260,051     10,249    270,300
      Crude oil (bbls/day)                      24,946      9,923     34,869
      Natural gas liquids (bbls/day)             4,325          -      4,325
      Total daily sales (BOE/day)               72,613     11,631     84,244

    Pricing(1)
      Natural gas (per Mcf)                    $  7.12    $  7.33    $  7.13
      Crude oil (per bbl)                      $ 57.24    $ 65.41    $ 59.56
      Natural gas liquids (per bbl)            $ 48.55    $     -    $ 48.55

    Capital Expenditures
      Development capital and office           $ 122.6    $  70.8    $ 193.4
      Acquisitions of oil and gas properties   $ 206.6    $  60.8    $ 267.4
      Dispositions of oil and gas properties   $  (5.5)   $     -    $  (5.5)

    Revenues
      Oil and gas sales(1)                     $ 631.4    $ 131.1    $ 762.5
      Royalties                                $(117.7)   $(26.1)(2) $(143.8)
      Commodity derivative instruments         $  (7.6)   $     -    $  (7.6)

    Expenses
      Operating                                $ 134.5    $   4.3    $ 138.8
      General and administrative               $  29.7    $   4.1    $  33.8
      Depletion, depreciation,
       amortization and accretion              $ 181.0    $  55.0    $ 236.0
      Current income taxes                     $     -    $   5.3    $   5.3


                                              Six months ended June 30, 2006
    (CDN$ millions, except per unit amounts)    Canada        U.S.     Total
    -----------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    264,304      5,618    269,922
      Crude oil (bbls/day)                      26,124      9,998     36,122
      Natural gas liquids (bbls/day)             4,634          -      4,634
      Total daily sales (BOE/day)               74,809     10,934     85,743

    Pricing(1)
      Natural gas (per Mcf)                   $   7.25    $  8.42    $  7.27
      Crude oil (per bbl)                     $  59.47    $ 68.92    $ 62.09
      Natural gas liquids (per bbl)           $  51.50    $     -    $ 51.50

    Capital Expenditures
      Development capital and office          $  182.8    $  54.9    $ 237.7
      Acquisitions of oil and gas properties  $   27.6    $  14.6    $  42.2
      Dispositions of oil and gas properties  $  (20.8)   $     -    $ (20.8)

    Revenues
      Oil and gas sales(1)                    $  671.9    $ 133.3    $ 805.2
      Royalties                               $ (134.1)   $(25.3)(2) $(159.4)
      Commodity derivative instruments        $  (13.7)   $     -    $ (13.7)

    Expenses
      Operating                               $  119.9    $   3.4    $ 123.3
      General and administrative              $   25.7    $   2.2    $  27.9
      Depletion, depreciation,
       amortization and accretion             $  178.0    $  54.7    $ 232.7
      Current income taxes                    $      -    $  10.0    $  10.0
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.

    

    Quarterly Financial Information - 2005 to 2007

    Oil and gas sales for the second quarter of 2007 were consistent with oil
and gas sales for the first quarter of 2007. Overall oil and gas sales
increased during 2005 due to increased crude oil production and higher
commodity prices, but decreased throughout 2006 as a result of softening
natural gas prices.
    Net income for the second quarter of 2007 was lower than net income for
the first quarter of 2007 mainly due to an increased future income tax expense
resulting from the enactment of the SIFT tax during the second quarter of
2007. Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating and G&A
costs, changes in future income tax provisions as well as changes to
accounting policies adopted during 2005 and 2007. Furthermore, changes in the
fair value of our commodity derivative instruments along with changes in fair
value of other financial instruments cause net income to fluctuate between
quarters.

    
    Quarterly information is summarized in the following table:

                                                              Net Income
                                                            per trust unit
    Quarterly Financial Information                     ---------------------
    ($ millions, except per        Oil and        Net
     trust unit amounts)        Gas Sales(1)    Income      Basic    Diluted
    -------------------------------------------------------------------------
    2007
    Second Quarter                 $  382.5  $    40.1  $    0.31  $    0.31
    First Quarter                     380.0      107.9       0.88       0.87
    -------------------------------------------------------------------------
    2006
    Fourth Quarter                 $  369.5  $   110.2  $    0.90  $    0.89
    Third Quarter                     398.0      161.3       1.31       1.31
    Second Quarter                    403.5      146.0       1.19       1.19
    First Quarter                     401.7      127.3       1.08       1.07
    ---------------------------------------------------
    Total                          $1,572.7  $   544.8  $    4.48  $    4.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    2005
    Fourth Quarter                 $  503.2  $   150.9  $    1.29  $    1.28
    Third Quarter                     398.7      107.1       0.97       0.97
    Second Quarter                    320.0      108.8       1.04       1.04
    First Quarter                     301.8       65.2       0.63       0.62
    ---------------------------------------------------
    Total                          $1,523.7  $   432.0  $    3.96  $    3.95
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    

    Liquidity and Capital Resources

    Sustainability of our Distributions and Asset Base

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

    Distribution Policy

    The amount of cash distributions is proposed by management and approved
by the Board of Directors. We continually assess distribution levels with
respect to forecasted cash flows, debt levels and capital spending plans. The
level of cash withheld has historically varied between 10% and 40% of annual
cash flow from operating activities and is dependent upon numerous factors,
the most significant of which are the prevailing commodity price environment,
our current levels of production, debt obligations, our access to equity
markets and funding requirements for our development capital program.
    At December 31, 2006 we changed our methodology for calculating payout
ratio to cash distributions to unitholders divided by cash flow from operating
activities (after changes in non-cash working capital) as presented on our
Consolidated Statements of Cash Flows. As a result, fluctuations in non-cash
changes in operating working capital will continue to impact our payout ratio
from quarter to quarter.
    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 second quarter of
2007 cash distributions of $162.6 million were funded entirely through cash
flow of $237.5 million. Our payout ratio, which is calculated as cash
distributions divided by cash flow, was 68% for the three months ended
June 30, 2007 compared to 78% for the same period in 2006. For the six months
ended June 30, 2007 our cash distributions were $320.3 million and were funded
entirely through cash flow of $430.7 million. Our payout ratio for the six
months ended June 30, 2007 was 74% compared to 79% for the six months ended
June 30, 2006.
    After consideration of cash distributions, the balance of our second
quarter cash flow of $74.9 million was used to fund 93% of our $80.4 million
in development capital spending. The balance of our development capital
expenditures and our property acquisitions (which primarily related to the
Kirby acquisition), were financed through a combination of debt and a portion
of the proceeds raised in our equity issue of $210.6 million which closed
April 10, 2007.
    In aggregate, our 2007 second quarter cash distributions of
$162.6 million and our development capital spending of $80.4 million totaled
$243.0 million, or approximately 102% of our cash flow of $237.5 million. We
rely on access to capital markets to the extent cash distributions and net
capital expenditures exceed cash flow. Over the long term we would expect to
support our distributions and capital expenditures with our cash flow;
however, we would continue to fund acquisitions and growth through additional
debt and equity. There will be years, especially when we are investing capital
in opportunities that do not immediately generate cash flow (such as our
Joslyn and Kirby oil sands projects) that this relationship will vary. In the
oil and gas sector, because of the nature of reserve reporting, the natural
reservoir declines and the risks involved in capital investment, it is not
possible to distinguish between capital spent on maintaining productive
capacity and capital spent on growth opportunities. Therefore we do not
disclose maintenance capital separate from development capital spending.
    For the three months ended June 30, 2007 our cash distributions exceeded
our net income by $122.5 million (2006 - $8.3 million) however net income
includes $167.4 million of non-cash items (2006 - $71.1 million) that do not
impact our cash flow. For the six months ended June 20, 2007 our cash
distributions exceeded our net income by $172.3 million (2006 - $31.3 million)
which includes $296.5 million of non-cash items (2006 - $160.2 million) that
do not impact our cash flow. Future income taxes can fluctuate from period to
period as a result of changes in tax rates (such as the enactment of the SIFT
tax during the second quarter of 2007), or changes in the royalty, interest
and dividends from our operating subsidiaries paid to the Fund. In addition,
other non-cash charges such as DDA&A are not a good proxy for the cost of
maintaining our productive capacity as they are based on the historical costs
of our PP&E and not the fair market value of replacing those assets within the
context of the current commodity price 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      Six months ended
    ($ millions, except                    June 30,              June 30,
     per unit amounts)                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities:                   $  237.5   $  198.4   $  430.7   $  387.7

    Use of cash flow:
      Cash distributions           $  162.6   $  154.3   $  320.3   $  304.6
      Capital expenditures             74.9       44.1      110.4       83.1
    -------------------------------------------------------------------------
                                   $  237.5   $  198.4   $  430.7   $  387.7

    Excess of cash flow over
     cash distributions            $   74.9   $   44.1   $  110.4   $   83.1

    Net income                     $   40.1   $  146.0   $  148.0   $  273.3
    Shortfall of net income
     over cash distributions       $ (122.5)  $   (8.3)  $ (172.3)  $  (31.3)

    Cash distributions per
     weighted average trust unit   $   1.27   $   1.26   $   2.54   $   2.53
    Payout ratio(1)                     68%        78%        74%        79%
    -------------------------------------------------------------------------
    (1) Based on cash distributions divided by cash flow from operating
        activities.

    
    Long-Term Debt

    Long-term debt at June 30, 2007 which was comprised of $412.9 million of
bank indebtedness and $247.1 million of senior unsecured notes, decreased to
$660.0 million from $679.8 million at December 31, 2006. With the adoption of
the financial instrument accounting standards (see Note 2) on January 1, 2007
we adjusted the carrying value of our US$175 million senior unsecured notes to
fair value of $208.2 million from their previous carrying value of
$268.3 million, a decrease of $60.1 million. Subsequent to this adoption
entry, our total long term debt has increased by approximately $40.3 million
from December 31, 2006. Increases in long-term debt resulting from the Jonah
and Kirby acquisitions more than offset decreases resulting from the April
2007 equity issue and the foreign exchange impact of the strengthening
Canadian dollar against the U.S. dollar on our U.S. denominated senior notes.
    We continue to maintain a conservative balance sheet with a long-term
debt to trailing cash flow ratio of 0.7 times as demonstrated below:

    
    Financial Leverage and Coverage      June 30, 2007     December 31, 2006
    -------------------------------------------------------------------------
    Long-term debt to trailing cash flow          0.7x                  0.8x
    Cash flow to interest expense                24.4x                 26.8x
    Long-term debt to long-term debt
     plus equity                                   19%                   20%
    -------------------------------------------------------------------------
    Long-term debt is measured net of cash.
    Cash flow and interest expense are 12-months trailing.
    

    There has been no change to our $850 million bank credit facility or our
senior unsecured notes during the quarter. 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 June 30, 2007 we are in compliance with our
debt covenants, the most restrictive of which limits our long term debt to
3 times trailing cash flow reflecting acquisitions on a pro forma basis. Refer
to "Debt of Enerplus" in our 2006 Annual Information Form for a detailed
description of these covenants.
    Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and 2011 and are more fully discussed in Note 7.
    We anticipate that we will continue to have adequate liquidity to fund
planned development capital spending during 2007 through a combination of cash
flow retained by the business and debt. A portion of our $415 million
development capital budget for 2007 is discretionary and could be revised
downward in the event of a commodity price downturn or similar economic event.

    Trust Unit Information

    We had 129,205,000 trust units outstanding at June 30, 2007 compared to
122,582,000 trust units at June 30, 2006 and 123,151,000 at December 31, 2006.
The weighted average basic number of trust units outstanding for the six
months ended June 30, 2007 was 125,849,000 (2006 - 120,311,000). At July 31,
2007 we had 129,359,000 trust units outstanding.
    For the three months ended June 30, 2007, 416,000 trust units (2006 -
350,000) were issued pursuant to the Trust Unit Monthly Distribution
Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights plan.
This resulted in $18.6 million (2006 - $14.6 million) of additional equity to
the Fund. For the six months ended June 30, 2007, 699,000 trust units
($31.7 million additional equity) were issued pursuant to DRIP and the trust
unit options and rights plans compared to 673,000 trust units ($28.0 million)
during the same period in 2006. For further details see Note 9.
    On April 10, 2007, in conjunction with the acquisition of Kirby we issued
1,105,000 trust units as part of the purchase price consideration representing
$54.8 million and also closed a public offering of 4,250,000 trust units for
net proceeds of $199.6 million.

    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 in 2007 and the remaining 5% and 10% respectively will be
treated as a tax deferred return of capital. Actual taxable amounts may vary
depending on actual distributions which are dependent upon production,
commodity prices and cash flow experienced throughout the year.
    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 July 2007, Enerplus estimated its non-resident ownership to be
approximately 70%.

    Recent Canadian Accounting Pronouncements

    CICA Section 3862 - Financial Instruments - Disclosures

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

    CICA Section 3863 - Financial Instruments - Presentation

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

    CICA Section 1535 - Capital Disclosures

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

    Internal Controls and Procedures

    There were no changes in our internal control over financial reporting
during the quarter ended June 30, 2007 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.

    Additional Information

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

    Forward-Looking Statements and Information

    This management's discussion and analysis ("MD&A") contains certain
forward-looking information and statements within the meaning of applicable
securities laws. The use of any of the words "expect", "anticipate",
"continue", "estimate", "objective", "ongoing", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are intended
to identify forward-looking information or statements. In particular, but
without limiting the foregoing, this MD&A contains forward-looking information
and statements pertaining to the following: the amount, timing and tax
treatment of cash distributions to unitholders; future payout ratios; future
tax treatment of income trusts such as the Fund; future structure of the Fund
and its subsidiaries; the Fund's tax pools; the volumes and estimated value of
the Fund's oil and gas reserves and resources; the volume and product mix of
the Fund's oil and gas production; future oil and natural gas prices and the
Fund's commodity risk management programs; the amount of future asset
retirement obligations; future liquidity and financial capacity; future
results from operations, cost estimates and royalty rates; future development,
exploration, and acquisition and development activities and related
expenditures, including with respect to both our conventional and oil sands
activities.
    The forward-looking information and statements contained in this MD&A
reflect several material factors and expectations and assumptions of the Fund
including, without limitation: that the Fund will continue to conduct its
operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing and in
certain circumstances, proposed tax and royalty regimes; the accuracy of the
estimates of the Fund's reserve volumes; and certain commodity price and other
cost assumptions. The Fund believes the material factors, expectations and
assumptions reflected in the forward-looking information and statements are
reasonable but no assurance can be given that these factors, expectations and
assumptions will prove to be correct.
    The forward-looking information and statements included in this MD&A are
not guarantees of future performance and should not be unduly relied upon.
Such information and statements involve known and unknown risks, uncertainties
and other factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking information or statements
including, without limitation: changes in commodity prices; unanticipated
operating results or production declines; changes in tax or environmental laws
or royalty rates; increased debt levels or debt service requirements;
inaccurate estimation of the Fund's oil and gas reserves volumes; limited,
unfavourable or no access to capital markets; increased costs; the impact of
competitors; and certain other risks detailed from time to time in the Fund's
public disclosure documents including, without limitation, those risks
identified in this MD&A, our MD&A for the year ended December 31, 2006, and in
the Fund's annual information form.
    The forward-looking information and statements contained in this MD&A
speak only as of the date of this MD&A, and none of the Fund or its
subsidiaries assumes any obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required pursuant to
applicable laws.

    

    CONSOLIDATED BALANCE SHEETS

    (CDN$ thousands)                                    June 30, December 31,
     (Unaudited)                                           2007         2006
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash                                          $     2,050  $       124
      Accounts receivable                               146,408      175,454
      Deferred financial assets (Note 3)                 12,664       23,612
      Other current                                       2,875        6,715
    -------------------------------------------------------------------------
                                                        163,997      205,905
    Property, plant and equipment (Note 4)            3,891,161    3,726,097
    Goodwill                                            206,358      221,578
    Other assets                                         57,633       50,224
    -------------------------------------------------------------------------
                                                    $ 4,319,149  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable                              $   243,520  $   284,286
      Distributions payable to unitholders               54,272       51,723
      Deferred financial credits (Note 3)                86,686            -
    -------------------------------------------------------------------------
                                                        384,478      336,009
    -------------------------------------------------------------------------
    Long-term debt (Note 7)                             659,995      679,774
    Future income taxes                                 362,157      331,340
    Asset retirement obligations (Note 6)               123,709      123,619
    -------------------------------------------------------------------------
                                                      1,145,861    1,134,733
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 9)                     4,003,318    3,713,126
    Accumulated deficit                              (1,149,130)    (971,085)
    Accumulated other comprehensive loss (Note 2)       (65,378)      (8,979)
    -------------------------------------------------------------------------
                                                      2,788,810    2,733,062
    -------------------------------------------------------------------------
                                                    $ 4,319,149  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

                                Three months ended          Six months ended
    (CDN$ thousands)                  June 30,                  June 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Accumulated income,
     beginning of period  $ 2,055,109  $ 1,535,470  $ 1,952,960  $ 1,408,178
    Adjustment for
     adoption of financial
     instruments standards
     (Note 2)                       -            -       (5,724)           -
    -------------------------------------------------------------------------
    Revised Accumulated
     income, beginning of
     period                 2,055,109    1,535,470    1,947,236    1,408,178
    Net income                 40,084      146,014      147,957      273,306
    -------------------------------------------------------------------------
    Accumulated income,
     end of period        $ 2,095,193  $ 1,681,484  $ 2,095,193  $ 1,681,484

    Accumulated cash
     distributions,
     beginning of period  $(3,081,716) $(2,459,950) $(2,924,045) $(2,309,705)
    Cash distributions       (162,607)    (154,348)    (320,278)    (304,593)
    -------------------------------------------------------------------------
    Accumulated cash
     distributions, end
     of period            $(3,244,323) $(2,614,298) $(3,244,323) $(2,614,298)

    -------------------------------------------------------------------------
    Accumulated deficit,
     end of period        $(1,149,130) $  (932,814) $(1,149,130) $  (932,814)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

                                Three months ended          Six months ended
    (CDN$ thousands)                  June 30,                  June 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Balance, beginning of
     period               $   (15,525) $   (12,509) $    (8,979) $   (15,568)
      Transition ad-
       justments (Note 2):
        Cash flow hedges            -            -          660            -
        Available for sale
         marketable secur-
         ities                      -            -       14,252            -
    Other comprehensive
     loss                     (49,853)     (26,708)     (71,311)     (23,649)
    -------------------------------------------------------------------------
    Balance, end of
     period               $   (65,378) $   (39,217) $   (65,378) $   (39,217)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF INCOME

    (CDN$ thousands
     except per trust           Three months ended          Six months ended
     unit amounts)                    June 30,                  June 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Revenues
      Oil and gas sales   $   387,926  $   409,078  $   773,797  $   816,916
      Royalties               (72,214)     (77,983)    (143,762)    (159,389)
      Commodity deriv-
       ative instruments
       (Notes 3 and 10)        17,954      (12,837)      (7,652)     (13,732)
      Other income                272          222       14,432        1,290
    -------------------------------------------------------------------------
                              333,938      318,480      636,815      645,085
    -------------------------------------------------------------------------
    Expenses
      Operating                72,756       65,106      138,786      123,271
      General and
       administrative (Note 9) 16,660       14,560       33,770       27,865
      Transportation            5,453        5,615       11,317       11,727
      Interest on long-
       term debt               11,847        7,110       19,962       15,006
      Foreign exchange
       gain (Note 8)           (3,956)      (2,408)      (3,474)      (2,254)
      Depletion, de-
       preciation,
       amortization and
       accretion              116,909      121,183      236,000      232,734
    -------------------------------------------------------------------------
                              219,669      211,166      436,361      408,349
    -------------------------------------------------------------------------
    Income before taxes       114,269      107,314      200,454      236,736
    Current taxes               3,227        6,147        5,291       10,009
    Future income tax
     expense / (recovery)      70,958      (44,847)      47,206      (46,579)
    -------------------------------------------------------------------------
    Net Income            $    40,084  $   146,014  $   147,957  $   273,306
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per trust
     unit
      Basic               $      0.31  $      1.19  $      1.18  $      2.27
      Diluted             $      0.31  $      1.19  $      1.18  $      2.26
    -------------------------------------------------------------------------
    Weighted average
     number of trust
     units outstanding
     (thousands)
      Basic                   128,361      122,379      125,849      120,311
      Diluted                 128,419      122,845      125,904      120,747
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                Three months ended          Six months ended
    (CDN$ thousands)                  June 30,                  June 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Net income            $    40,084  $   146,014  $   147,957  $   273,306
    -------------------------------------------------------------------------

    Other comprehensive
     income / loss, net
     of tax:
      Unrealized gains/
       (losses) on market-
       able securities          2,502            -         (654)           -
      Realized gains on
       marketable secur-
       ities included in
       net income                   -            -      (11,654)           -
      Gains and losses on
       derivatives desig-
       nated as hedges in
       prior periods
       included in net
       income                    (176)           -         (380)           -
    Change in cumulative
     translation adjust-
     ment                     (52,179)     (26,708)     (58,623)     (23,649)
    -------------------------------------------------------------------------
    Other comprehensive loss  (49,853)     (26,708)     (71,311)     (23,649)

    -------------------------------------------------------------------------
    Comprehensive (loss) /
     income (Note 2)      $    (9,769) $   119,306  $    76,646  $   249,657
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                Three months ended          Six months ended
    (CDN$ thousands)                  June 30,                  June 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Operating Activities
    Net income            $    40,084  $   146,014  $   147,957  $   273,306
    Non-cash items add/
     (deduct):

      Depletion,
       depreciation,
       amortization
       and accretion          116,909      121,183      236,000      232,734
      Change in fair value
       of derivative
       instruments (Note 3)    (1,394)      (3,774)      33,453      (25,759)
      Unit based com-
       pensation (Note 9)       2,107        1,339        4,218        2,526
      Foreign exchange on
       translation of
       senior notes
       (Note 8)               (20,808)      (2,813)     (23,690)      (2,748)
      Future income tax        70,958      (44,847)      47,206      (46,579)
      Amortization of
       senior notes
       premium                   (159)           -         (328)           -
      Reclassification
       adjustments from
       AOCI to net
       income                    (176)           -         (380)           -
    Gain on sale of
     marketable
     securities                     -            -      (14,055)           -
    Asset retirement costs
     incurred (Note 6)         (3,803)      (2,521)      (7,117)      (5,584)
    -------------------------------------------------------------------------
                              203,718      214,581      423,264      427,896
    Decrease/(Increase)
     in non-cash working
     capital                   33,764      (16,177)       7,399      (40,211)
    -------------------------------------------------------------------------
    Cash flow from
     operating activities     237,482      198,404      430,663      387,685
    -------------------------------------------------------------------------
    Financing Activities
    Issue of trust units,
     net of issue costs
     (Note 9)                 218,204       14,564      231,224      268,244
    Cash distributions to
     unitholders             (162,607)    (154,348)    (320,278)    (304,593)
    (Decrease)/Increase in
     bank credit facilities   (35,992)      80,255       64,350      (52,599)
    Decrease in non-cash
     financing working
     capital                      180          131        2,549        2,131
    -------------------------------------------------------------------------
    Cash flow from
     financing activities      19,785      (59,398)     (22,155)     (86,817)
    -------------------------------------------------------------------------
    Investing Activities
    Capital expenditures      (82,000)    (108,133)    (193,354)    (237,693)
    Property acquisitions    (149,266)     (12,230)    (212,644)     (42,257)
    Property dispositions      (1,107)       1,089       (1,152)       1,278
    Proceeds on sale of
     marketable securities          -            -       16,467            -
    Increase in non-cash
     investing working
     capital                  (20,627)     (19,076)     (14,497)     (30,509)
    -------------------------------------------------------------------------
    Cash flow from invest-
     ing activities          (253,000)    (138,350)    (405,180)    (309,181)
    -------------------------------------------------------------------------
    Effect of exchange
     rate changes on cash      (2,311)      (1,269)      (1,402)      (1,128)
    -------------------------------------------------------------------------
    Change in cash              1,956         (613)       1,926       (9,441)
    Cash, beginning of
     period                        94        1,265          124       10,093
    -------------------------------------------------------------------------
    Cash, end of period   $     2,050  $       652  $     2,050  $       652
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash Flow Information
    Cash income taxes
     paid                 $     4,005  $     3,516  $     7,246  $     3,770
    Cash interest paid    $    14,644  $    10,238  $    20,730  $    14,761



    ENERPLUS RE

SOURCES FUND NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars and thousands of units except per unit amounts) (Unaudited) 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, 2006, except as identified in Note 2. 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, 2006. The disclosures provided below are incremental to those included in the 2006 annual consolidated financial statements of the Fund. 2. CHANGES IN ACCOUNTING POLICIES Financial Instruments Effective January 1, 2007, the Fund adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 1530, Comprehensive Income, Handbook Section 3855, Financial Instruments - Recognition and Measurement, and Handbook Section 3865, Hedges. These standards were adopted prospectively pursuant to their respective adoption provisions, and therefore there is no effect on prior periods. Comprehensive Income CICA Handbook Section 1530 introduces comprehensive income, which consists of net income and other comprehensive income ("OCI"). OCI represents changes in equity during a period arising from transactions and other events with non-owner sources and includes unrealized gains and losses on marketable securities classified as available-for-sale along with unrealized foreign currency translation gains or losses arising from self-sustaining foreign operations, among other things. The Consolidated Statements of Comprehensive Income include a calculation of comprehensive income, while the cumulative changes in OCI are included in the Statements of Accumulated Other Comprehensive Income (AOCI). Financial Instruments - Recognition and Measurement CICA Handbook Section 3855 establishes the criteria for recognizing and measuring financial assets, financial liabilities and non- financial derivatives. Under this standard, all financial instruments are required to be measured at fair value on recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Financial assets and financial liabilities classified as held-for- trading are measured at fair value with changes in fair value recognized in net income. Financial assets classified as loans and receivables along with financial liabilities classified as other liabilities are measured at amortized cost using the effective interest rate method. Financial assets classified as available-for- sale are measured at fair value with changes in fair value recognized in OCI. Investments in equity instruments classified as available- for-sale that do not have a quoted price in an active market are measured at cost. Transaction costs or fees attributable to the acquisition, issue, or disposal of a financial asset or liability are expensed immediately to net income. Derivative instruments are recorded on the consolidated balance sheets at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net income with the exception of derivatives that are designated as effective cash flow hedges. Refer to the Hedges section for further detail. Hedges CICA Handbook Section 3865 specifies the criteria and method of accounting for each of the designated hedging strategies. When hedge accounting is discontinued for a cash flow hedge, the amounts previously recognized in AOCI are reclassified to net income over the remaining term of the hedged item. When hedge accounting is discontinued for a fair value hedge, the carrying value of the hedged item is no longer adjusted. Any difference between the carrying value and the face value or principal amount of the hedged item is amortized to net income over the remaining term of the original hedging relationship using the effective interest method. Impact upon Adoption of Sections 1530, 3855 and 3865 As a result of the adoption of these standards on January 1, 2007 the Fund elected to stop designating its interest rate and electricity swaps as cash flow hedges and recorded these items on the consolidated balance sheet at their fair values with the offset recorded to opening accumulated other comprehensive income. In addition, the Fund elected to stop designating its cross currency and interest rate swap ("CCIRS") as a fair value hedge and recorded the CCIRS on the consolidated balance sheet at fair value with the offset recorded to opening accumulated deficit. In conjunction, the underlying US$175,000,000 senior unsecured notes were recorded at fair value with the offset recorded to opening accumulated deficit. The Fund's investments in marketable securities have been classified as available-for-sale and were therefore recorded on the consolidated balance sheet at fair value with the offset recorded to opening AOCI. Deferred charges of $1,523,000 associated with issuance of the senior unsecured notes were recorded to the opening accumulated deficit. Amounts previously recorded in the cumulative translation adjustment were reclassified into opening AOCI. Our prior year comparative statements have been restated to reflect this change. The Fund has recorded the following transition adjustments as of January 1, 2007 in the Consolidated Financial Statements: (a) an increase of $1,494,000 to deferred financial assets to record the electricity swaps at fair value; (b) an increase to other current assets of $14,493,000 to record publicly traded marketable securities at fair value; (c) an increase of $1,708,000 to other assets, consisting of $3,231,000 to record publicly traded marketable securities at fair value less $1,523,000 to write-off the deferred charges associated with the issuance of the senior unsecured notes; (d) an increase of $65,675,000 to deferred financial credits to record the CCIRS and interest rates swaps at fair value; (e) a decrease to long-term debt of $60,111,000 to record the US$175,000,000 senior unsecured note at fair value; (f) an increase to future income taxes of $ 2,943,000 to reflect the tax impact of the adoption entries; (g) an increase of $5,724,000, net of taxes, to the opening accumulated deficit; (h) recognition in AOCI of $14,912,000, net of taxes, related to the net gains on marketable securities classified as available-for-sale along with the fair value of the interest rate and power swaps formerly designated as cash flow hedges. In addition, the Fund reclassified to AOCI $8,979,000 of net unrealized foreign currency losses that were previously presented as a separate item in equity. These transition adjustments are summarized below. Impact of transition adjustment on selected consolidated balance sheets line items: Transition adjustment as (CDN$ thousands) at January 1, 2007 ------------------------------------------------------------------------- Deferred financial assets $1,494 Other current assets 14,493 Other assets 1,708 Deferred credits 65,675 Long-term debt (60,111) Future income taxes 2,943 Accumulated deficit (5,724) Cumulative translation adjustment 8,979 Accumulated other comprehensive income 5,933 ------------------------------------------------------------------------- As a result of these changes, net income decreased by $956,000 ($1,347,000 before future income taxes of $391,000) and $89,000 ($126,000 before future income taxes of $37,000 for the three and six months ended June 30, 2007 respectively. Both the basic and diluted net income per trust unit calculations for the three months ended June 30, 2007 decreased by $0.01 and were unchanged for the six months ended June 30, 2007. 3. DEFERRED FINANCIAL ASSETS AND CREDITS The deferred financial assets and credits result from recording our derivative financial instruments at fair value. The deferred financial asset relating to crude oil and natural gas instruments of $9,182,000 at June 30, 2007 consists of the fair value of the financial instruments of $22,749,000 less the related deferred premiums of $13,567,000. Cross Currency Elec- Commodity Interest Interest tricity Derivative ($ thousands) Rate Swap Rate Swaps Swaps Instruments Total ------------------------------------------------------------------------- Deferred financial assets/(credits) as at December 31, 2006 $ - $ - $ - $ 23,612 $ 23,612 Adoption of finan- cial instruments standards(1) (673) (65,002) 1,494 - (64,181) Change in fair value asset/ (credits) 2,100(2) (21,684)(3) 561(4) (14,430)(5) (33,453) ------------------------------------------------------------------------- Deferred financial assets/(credits) as at June 30, 2007 $ 1,427 $(86,686) $ 2,055 $ 9,182 $(74,022) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The adoption of the financial instruments standards on January 1, 2007 resulted in a decrease to the deferred financial assets balance. See Note 2 for further details. (2) Recorded in interest expense. (3) Recorded in foreign exchange expense (loss of $18,774) and interest expense (loss of $2,910). (4) Recorded in operating expense. (5) Recorded in commodity derivative instruments (see below). The following table summarizes the income statement effects of commodity derivative instruments: Commodity Derivative Three months ended Six months ended Instruments June 30, June 30, ($ thousands) 2007 2006 2007 2006 ------------------------------------------------------------------------- Change in fair value $(19,052) $(22,218) $ 14,430 $(62,499) Amortization of deferred financial assets - 18,444 - 36,740 Realized cash costs/(gains), net 1,098 16,611 (6,778) 39,491 ------------------------------------------------------------------------- Commodity derivative instruments $(17,954) $ 12,837 $ 7,652 $ 13,732 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. PROPERTY, PLANT AND EQUIPMENT June 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Property, plant and equipment $ 6,237,441 $ 5,855,511 Accumulated depletion, depreciation and accretion (2,346,280) (2,129,414) ------------------------------------------------------------------------- Net property, plant and equipment $ 3,891,161 $ 3,726,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capitalized development G&A of $8,158,000 (2006 - $6,696,000) is included in property, plant and equipment ("PP&E") for the six months ended June 30, 2007. Excluded from PP&E for the purpose of the depletion and depreciation calculation is $99,376,000 (2006 - $57,799,000) related to the Joslyn development project and $203,083,000 (2006 - nil) related to the Kirby development project, both of which have not yet commenced commercial production. 5. PROPERTY ACQUISITION On April 10, 2007 the Fund acquired a 90% interest in the Kirby Oil Sands Partnership ("Kirby") for total consideration of $182,800,000 consisting of $128,050,000 in cash and the issuance of 1,104,945 trust units at a price of $49.55 per unit ($54,750,000 of equity). On June 22, 2007, the Fund acquired the remaining 10% interest in Kirby for cash consideration of $20,276,000. The acquisition of Kirby has been accounted for as an asset acquisition pursuant to the guidance in the Emerging Issues Committee Abstract 124. 6. ASSET RETIREMENT OBLIGATIONS The following table reconciles the Fund's asset retirement obligations: Six months ended Year ended June 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning of period $ 123,619 $ 110,606 Changes in estimates 3,653 12,757 Acquisition and development activity 969 5,574 Dispositions (759) (45) Asset retirement obligations settled (7,117) (11,514) Accretion expense 3,344 6,241 ------------------------------------------------------------------------- Asset retirement obligations, end of period $ 123,709 $ 123,619 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. LONG-TERM DEBT June 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Bank credit facilities (a) $ 412,870 $ 348,520 Senior notes (b) US$175 million (issued June 19, 2002) 189,701 268,328 US$54 million (issued October 1, 2003) 57,424 62,926 ------------------------------------------------------------------------- Total long-term debt $ 659,995 $ 679,774 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (a) Unsecured Bank Credit Facility Enerplus has an $850,000,000 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 six months ended June 30, 2007 was 4.9% (2006 - 4.6%). (b) Senior Unsecured Notes On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes that mature October 1, 2015. The notes have a coupon rate of 5.46% priced at par with interest paid semi-annually on April 1 and October 1 of each year. Principal payments are required in five equal installments beginning October 1, 2011 and ending October 1, 2015. The notes are subject to fluctuations in foreign exchange rates and are translated into Canadian dollars using the period end foreign exchange rate. On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes that mature June 19, 2014. The notes have a coupon rate of 6.62% priced at par, with interest paid semi-annually on June 19 and December 19 of each year. Principal payments are required in five equal installments beginning June 19, 2010 and ending June 19, 2014. Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a cross currency interest rate swap ("CCIRS") with a syndicate of financial institutions. Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian bankers' acceptances, plus 1.18%. On January 1, 2007 in conjunction with the adoption of CICA Sections 3855 and 3865, the Fund elected to stop designating the CCIRS as a fair value hedge on the US$175,000,000 senior notes. As a result, the Fund recorded the senior notes at their fair value of US$178,681,000 (CDN $208,217,000) with the offset to opening accumulated deficit. In addition, the Fund recorded a liability of $65,002,000 with the offset to opening accumulated deficit, which represented the fair value of the CCIRS. The premium amount of US$3,681,000, representing the difference between the January 1, 2007 fair value and the face amount of the senior notes, will be amortized to net income over the remaining term of the notes using the effective interest method. The effective interest rate over the remaining term of the senior notes is 6.16%. The senior notes are carried at amortized cost and are translated into Canadian dollars using the period end foreign exchange rate. At June 30, 2007 the amortized cost of the US$175,000,000 senior notes was US$178,391,000. 8. FOREIGN EXCHANGE Three months ended Six months ended June 30, June 30, ($ thousands) 2007 2006 2007 2006 ------------------------------------------------------------------------- Unrealized foreign exchange gain on translation of U.S. dollar denominated senior notes $(20,808) $ (2,813) $(23,690) $ (2,748) Unrealized foreign exchange loss on cross currency interest rate swap 15,998 - 18,774 - Realized foreign exchange loss 854 405 1,442 494 ------------------------------------------------------------------------- Foreign exchange gain $ (3,956) $ (2,408) $ (3,474) $ (2,254) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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. 9. FUND CAPITAL (a) Unitholders' Capital Trust Units Authorized: Unlimited number of trust units Six months ended Year ended June 30, 2007 December 31, 2006 Issued: (thousands) Units Amount Units Amount ------------------------------------------------------------------------- Balance before Contributed Surplus, beginning of period 123,151 $3,706,821 117,539 $3,407,567 Issued for cash: Pursuant to public offerings 4,250 199,558 4,370 240,287 Pursuant to rights plans 118 4,153 640 22,974 Trust unit rights incentive plan (non-cash) - exercised - 1,141 - 3,065 DRIP(*), net of redemptions 581 27,513 602 32,928 Issued for acquisition of property interests (non-cash) 1,105 54,750 - - ------------------------------------------------------------------------- 129,205 3,993,936 123,151 3,706,821 Contributed Surplus (Trust Unit Rights Plan) - 9,382 - 6,305 ------------------------------------------------------------------------- Balance, end of period 129,205 $4,003,318 123,151 $3,713,126 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Distribution Reinvestment and Unit Purchase Plan Six months ended Year ended June 30, December 31, Contributed Surplus ($ thousands) 2007 2006 ------------------------------------------------------------------------- Balance, beginning of period $ 6,305 $ 3,047 Trust unit rights incentive plan (non-cash) - exercised (1,141) (3,065) Trust unit rights incentive plan (non-cash) - expensed 4,218 6,323 ------------------------------------------------------------------------- Balance, end of period $ 9,382 $ 6,305 ------------------------------------------------------------------------- ------------------------------------------------------------------------- On April 10, 2007 the Fund closed an equity offering of 4,250,000 trust units at a price of $49.55 per unit for gross proceeds of $210,588,000 ($199,558,000 net of issuance costs). These trust units were eligible for the April 20, 2007 cash distribution paid to unitholders of record at the close of business on April 10, 2007. In conjunction with the acquisition of Kirby on April 10, 2007, the Fund issued 1,105,000 trust units at a price of $49.55 per unit for gross proceeds of $54,750,000. (b) Trust Unit Rights Incentive Plan As at June 30, 2007, a total of 3,473,000 rights issued pursuant to the Trust Unit Rights Incentive Plan ("Rights Plan") with an average exercise price of $48.37 were outstanding. This represents 2.7% of the total trust units outstanding of which 1,062,000 rights with an average exercise price of $42.87 were exercisable. Under the Rights Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter may result in a reduction in the exercise price of the rights. Results for the first and second quarters of 2007 reduced the exercise price of the outstanding rights by $0.51 per trust unit (effective July 2007) and $0.51 per trust unit (effective October 2007). Activity for the rights issued pursuant to the Rights Plan is as follows: Six months ended Year ended June 30, 2007 December 31, 2006 ------------------------------------------- Weighted Weighted Number of Average Number of Average Rights Exercise Rights Exercise (000's) Price(1) (000's) Price(1) ------------------------------------------------------------------------- Trust unit rights outstanding Beginning of period 3,079 $48.53 2,621 $42.80 Granted 638 49.85 1,473 54.49 Exercised (118) 35.11 (640) 35.94 Cancelled (126) 50.62 (375) 46.35 ------------------------------------------------------------------------- End of period 3,473 48.37 3,079 48.53 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Rights exercisable at the end of the period 1,062 $42.87 809 $39.81 ------------------------------------------------------------------------- (1) Exercise price reflects grant prices less reduction in strike price discussed above. The Fund uses a binomial option-pricing model to calculate the estimated fair value of rights under the plan. Non-cash compensation costs for the three and six months ended June 30, 2007 were $2,107,000 ($0.02 per unit) and $4,218,000 ($0.03 per unit) respectively. The non-cash compensation costs for the three and six months ended June 30, 2006 were $1,339,000 ($0.01 per unit) and $2,526,000 ($0.02 per unit) respectively. (c) Basic and Diluted per Trust Unit Calculations Net income per trust unit has been determined based on the following: Six months ended June 30, (thousands) 2007 2006 ------------------------------------------------------------------------- Weighted average units 125,849 120,311 Dilutive impact of rights 55 436 ------------------------------------------------------------------------- Diluted trust units 125,904 120,747 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (d) Cash Distributions to Unitholders Cash distributions to unitholders for the three months ended June 30, 2007 were $162,607,000 (2006 - $154,348,000). Cash distributions to unitholders for the six months ended June 30, 2007 were $320,278,000 (2006 - $304,593,000). Cash distributions are determined by the Board of Directors in accordance with the Trust indenture and are paid monthly. 10. FINANCIAL INSTRUMENTS (a) Fair Value of Financial Instruments As a result of the adoption of the new financial instrument and hedging accounting standards described in Note 2, certain financial instruments are now measured and reported on the balance sheet at fair value which were previously reported at amortized cost. The fair value of a financial instrument is the amount of consideration that would be agreed upon in an arm's-length transaction between knowledgeable, willing parties who are under no compulsion to act. Fair values are determined by reference to quoted bid or ask prices, as appropriate, in the most advantageous active market for that instrument to which we have immediate access. Where bid and ask prices are unavailable, we would use the closing price of the most recent transaction for that instrument. In the absence of an active market, we determine fair values based on prevailing market rates for instruments with similar characteristics. Fair values may also be determined based on internal and external valuation models, such as option pricing models and discounted cash flow analysis, that use observable market based inputs and assumptions. (b) Carrying Value and Fair Value of Financial Instruments i. Cash Cash is classified as held-for-trading and is reported at fair value. ii. Accounts Receivable Accounts receivable are classified as loans and receivables are reported at amortized cost. At June 30, 2007 the carrying value of accounts receivable approximated their fair value. iii. Marketable Securities Marketable securities with a quoted market price in an active market are classified as available-for-sale and are reported at fair value, with changes in fair value recorded in other comprehensive income. As at June 30, 2007 the Fund reported investments in marketable securities of publicly traded marketable securities at a fair value of $12,308,000. For the three months ended June 30, 2007, the change in fair value of these investments represented a gain $3,538,000 ($2,502,000 net of tax). For the six months ended June 30, 2007 the change in fair value of these investments represented a loss of $923,000 ($654,000 net of tax). Marketable securities without a quoted market price in an active market are reported at amortized cost. As at June 30, 2007 the Fund reported investments in marketable securities of private companies at an amortized cost of $45,325,000. During the first quarter of 2007 the Fund disposed of certain marketable securities which resulted in a gain of $14,493,000 ($11,654,000 net of tax) being reclassified from accumulated other comprehensive income to net income. Marketable securities are included in other current assets or other assets on the Consolidated Balance Sheet. Realized gains and losses on marketable securities are included in other income. iii. Accounts Payable & Distributions Payable to Unitholders Accounts payable as well as Distributions payable to unitholders are classified as other liabilities and are reported at amortized cost. At June 30, 2007 the carrying value of these accounts approximated their fair value. iv. Long-term debt Bank Credit Facilities The bank credit facilities are classified as other liabilities and are reported at amortized cost. At June 30, 2007 the carrying value of the bank credit facilities approximated their fair value. US$54 million senior notes The US$54,000,000 million senior notes, which are classified as other liabilities, are reported at their amortized cost of US$54,000,000 and are translated into Canadian dollars at the period end exchange rate. At June 30, 2007 the Canadian dollar amortized cost of the senior notes was approximately $57,424,000. US$175 million senior notes The US$175,000,000 million senior notes, which are classified as other liabilities, are reported at amortized cost of US$178,391,000 and are translated to Canadian dollars at the period end exchange rate. At June 30, 2007 the Canadian dollar amortized cost of the senior notes was approximately $189,701,000. v. Derivative Financial Instruments Interest Rate Swaps The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 4.10% to 4.61% before banking fees that are expected to range between 0.55% and 1.10%. These interest rate swaps mature between June 2011 and January 2012. The interest rate swaps are classified as held-for-trading and are reported at fair value. At June 30, 2007 the fair value of the interest rate swaps represented an asset of $1,427,000. For the three months ended June 30, 2007, the change in fair value of these contracts represented an unrealized gain of $1,919,000. Cross Currency Interest Rate Swap (CCIRS) Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a CCIRS with a syndicate of financial institutions. Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian bankers' acceptances, plus 1.18%. The CCIRS is classified as held-for-trading and is reported at fair value. At June 30, 2007 the fair value of the CCIRS represented a liability of $86,686,000. For the three months ended June 30, 2007, the change in fair value of the CCIRS represented an unrealized loss of $20,191,000. Crude Oil Instruments Enerplus has entered into the following financial option contracts to reduce the impact of a downward movement in crude oil prices. These contracts are classified as held-for-trading and are reported at fair value. At June 30, 2007 the fair value of these contracts represented a liability of $8,285,000. For the three months ended June 30, 2007, the change in fair value of these contracts represented an unrealized loss of $6,327,000. The net premium cost of the crude oil instruments entered into as of June 30, 2007 is $11,212,000. The following table summarizes the Fund's crude oil risk management positions at July 25, 2007: WTI US$/bbl ------------------------------------ Fixed Daily Price Volumes Sold Purchased Sold and bbls/day Call Put Put Swaps ------------------------------------------------------------------------- Term July 1, 2007 - December 31, 2007 Put 5,000 - $71.00 - - Put 2,500 - $68.00 - - Put 2,500 - $65.70 - - Swap 2,500 - - - $66.24 January 1, 2008 - December 31, 2008 Collar 750 $77.00 $67.00 - - 3-Way option(1) 1,000 $84.00 $66.00 $50.00 - 3-Way option(1) 1,000 $84.00 $66.00 $52.00 - 3-Way option(1) 1,000 $86.00 $68.00 $52.00 - Swap(2) 750 - - - $72.94 Swap(2) 750 - - - $73.35 ------------------------------------------------------------------------- (1) Financial contracts entered into during the second quarter of 2007. (2) Financial contracts entered into subsequent to June 30, 2007. Natural Gas Instruments Enerplus has certain physical and financial contracts outstanding as at July 25, 2007 on its natural gas production that are detailed below. In addition, the Fund has outstanding physical natural gas contracts that provide the Fund a premium of $0.40/Mcf on 23.5MMcf/day for the month of July 2007. These contracts are classified as held-for-trading and are reported at fair value. At June 30, 2007 the fair value of these contracts represented an asset of $17,467,000. For the three months ended June 30, 2007, the change in fair value of these contracts represented an unrealized gain of $25,379,000. The net premium cost of the financial natural gas instruments entered into as of June 30, 2007 is $2,355,000. The following table summarizes the Fund's natural gas risk management positions at July 25, 2007: AECO CDN$/Mcf ------------------------------------ Fixed Daily Price Volumes Sold Purchased Sold and MMcf/day Call Put Put Swaps ------------------------------------------------------------------------- Term July 1, 2007 - October 31, 2007 Collar 6.6 $10.02 $7.50 - - Collar 6.6 $9.00 $7.50 - - Collar 9.5 $9.10 $7.10 - - Collar 9.5 $9.15 $7.14 - - Collar 9.5 $9.50 $7.20 - - Costless Collar 4.7 $8.02 $7.17 - - Costless Collar 4.7 $8.23 $7.28 - - Costless Collar 4.7 $8.20 $7.50 3-Way option 4.7 $9.50 $7.75 $5.49 - Put 4.7 - $7.28 - - Swap 6.6 - - - $7.60 Swap 4.7 - - - $7.33 Swap 2.4 - - - $7.84 Swap 2.4 - - - $7.96 Swap 7.1 - - - $7.17 Swap 2.4 - - - $7.70 Swap 2.4 - - - $7.53 Swap 2.4 - - - $8.35 November 1, 2007 - March 31, 2008 Collar 2.4 $9.95 $8.00 - - Collar(1) 2.4 $10.15 $8.00 - - 3-Way option 4.7 $10.50 $8.20 $5.70 - 3-Way option 4.7 $11.61 $8.97 $6.33 - 3-Way option(1) 4.7 $11.61 $8.97 $6.33 - 3-Way option(1) 4.7 $11.08 $8.55 $6.01 - Swap 4.7 - - - $8.70 Swap(1) 2.4 - - - $9.01 April 1, 2008 - October 31, 2008 3-Way option(1) 5.7 $9.50 $7.54 $5.28 - Swap(1) 4.7 - - - $8.18 2007 - 2010 Physical (escalated pricing) 2.0 - - - $2.52 ------------------------------------------------------------------------- (1) Financial contracts entered into during the second quarter of 2007. (*) There were no financial contracts entered into subsequent to June 30, 2007. Electricity Instruments The Fund has entered into electricity swaps that fix the price of electricity. These contracts are classified as held-for-trading and are reported at fair value. At June 30, 2007 the fair value of these contracts represented an asset of $2,055,000. For the three months ended June 30, 2007, the change in fair value of these contracts represented an unrealized gain of $614,000. Unrealized gains or losses resulting from changes in fair value along with realized gains or losses on settlement of the electricity contracts are recognized as operating costs. The following table summarizes the Fund's electricity management positions at July 25, 2007. Price Term Volumes MWh CDN$/MWh ------------------------------------------------------------------------- July 1, 2007 - December 31, 2007 5.0 $61.50 July 1, 2007 - December 31, 2007 4.0 $62.90 April 1, 2008 - September 30, 2008 4.0 $63.00 ------------------------------------------------------------------------- The Fund did not enter into any new electricity contracts in the second quarter of 2007. This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the amount, timing and tax treatment of cash distributions to unitholders; future payout ratios; future tax treatment of income trusts such as the Fund; the volumes and estimated value of the Fund's future oil and gas reserves; the volume and product mix of the Fund's oil and gas production; future oil and natural gas prices and the Fund's commodity risk management programs; the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations, cost estimates and royalty rates; future development, exploration, acquisition and development activities, and related expenditures, including with respect to both our conventional and oil sands activities. The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of the Fund including, without limitation: that the Fund will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, proposed) tax and royalty regimes; the accuracy of the estimates of the Fund's reserve volumes; and certain commodity price and other cost assumptions. The Fund believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; unanticipated operating results or production declines; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements; inaccurate estimation of the Fund's oil and gas reserves volumes; limited, unfavourable or no access to capital markets; increased costs; the impact of competitors; and certain other risks detailed from time to time in the Fund's public disclosure documents (including, without limitation, those risks identified in this news release and in the Fund's annual information form). The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of the Fund or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. Gordon J. Kerr President & Chief Executive Officer

For further information:

For further information: and a complete copy of the 2007 Second Quarter
Interim Report, please contact Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com


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