Enerplus announces 2007 third quarter operating and financial results



    TSX: ERF.un
    NYSE:   ERF

    CALGARY, Nov. 9 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our results from operations for the period ending September 30,
2007. Highlights are as follows:

    
    -   Monthly cash distributions to Unitholders were maintained at
        $0.42 per unit throughout the third quarter, totaling $1.26 per unit
        paid during the quarter.

    -   Our payout ratio averaged 70% for the quarter and we maintained our
        balance sheet strength with a trailing twelve month debt to cash flow
        multiple of 0.7x.

    -   Approximately $25 million has been eliminated from our full year
        capital development budget, primarily in non-operated deep gas,
        shallow gas and coalbed methane activities. We now anticipate our
        full year capital development spending in 2007 will be $390 million
        versus our previous estimate of $415 million.

    -   Operationally, a reduction in capital spending, lower than
        anticipated initial production rates on our third well per section
        program in the U.S. Bakken and higher than anticipated downtime and
        unplanned turnarounds have resulted in production averaging
        79,891 BOE/day during the quarter. As a result, we are lowering our
        forecast for annual average and exit production by 3%.

    -   We continued with our low-risk development program during the
        quarter, investing $90.6 million into our asset base with our highest
        concentration of spending on oil properties in southeast
        Saskatchewan, Manitoba and Montana. In total we drilled 184 gross
        wells (101.2 net) during the quarter with a 99% success rate.

    -   With the Alberta government's announcement of a new royalty regime
        for Alberta, our best estimate of the impact of the new level of
        royalties on our conventional business will be approximately
        $15 - $20 million annually representing a reduction of approximately
        2% to cash flow within the context of prices and production
        experienced in 2007.

    -   September marks the fourteenth consecutive month where no Enerplus
        employee has suffered a lost time injury and the seventh consecutive
        month without an employee injury that required medical aid.
    

    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 nine months ended September 30,               2007          2006
    -------------------------------------------------------------------------
    Financial (000's)
      Net Income                                     $ 240,990     $ 434,623
      Cash Flow from Operating Activities              663,464       656,589
      Cash Distributions to Unitholders(1)             483,388       459,293
      Cash Withheld for Acquisitions and
       Capital Expenditures                            180,076       197,296
      Debt Outstanding (net of cash)                   649,829       589,420
      Development Capital Spending                     281,045       368,117
      Acquisitions                                     269,149        46,553
      Divestments                                        5,569        21,021
    Financial per Unit(2)
      Net Income                                     $    1.90     $    3.59
      Cash Flow from Operating Activities                 5.22          5.42
      Cash Distributions to Unitholders(1)                3.81          3.79
      Cash Withheld for Acquisitions and
       Capital Expenditures                               1.42          1.63
      Payout Ratio(3)                                       73%           70%
    Selected Financial Results per BOE(4)
      Oil & Gas Sales(5)                             $   49.89     $   51.65
      Royalties                                          (9.38)        (9.89)
      Commodity Derivative Instruments                    0.63         (1.73)
      Operating Costs                                    (9.32)        (7.85)
      General and Administrative                         (2.00)        (1.66)
      Interest and Foreign Exchange                      (1.34)        (0.91)
      Taxes                                              (0.46)        (0.56)
      Restoration and Abandonment                        (0.47)        (0.31)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash working capital             $   27.55     $   28.74
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Weighted Average Number of Trust Units
     Outstanding (thousands)                           127,031       121,120
    Debt/Trailing 12 Month Cash Flow Ratio                0.7x          0.6x
    -------------------------------------------------------------------------


    SELECTED OPERATING RESULTS

    For the nine months ended September 30,               2007          2006
    -------------------------------------------------------------------------
    Average Daily Production
      Natural gas (Mcf/day)                            263,884       268,700
      Crude oil (bbls/day)                              34,602        36,065
      NGLs (bbls/day)                                    4,194         4,487
      Total (BOE/day) (6:1)                             82,777        85,335

      % Natural gas                                         53%           52%

    Average Selling Price(5)

      Natural gas (per Mcf)                          $    6.63     $    6.89
      Crude oil (per bbl)                            $   62.75     $   64.27
      NGLs (per bbl)                                 $   49.26     $   52.49

      US$ exchange rate                                   0.91          0.88

    Net Wells Drilled                                      177           304
    Success Rate                                            99%           99%
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        to unitholders per unit will not correspond to the actual cumulative
        monthly distributions of $3.78 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 nine months ended September 30, 2007         (CDN$)       (US$)
    -------------------------------------------------------------------------

    High                                             $   53.70     $ 50.75
    Low                                              $   41.00     $ 38.11
    Close                                            $   46.90     $ 47.20


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

    First Quarter Total                              $    1.26     $  1.12
    Second Quarter Total                             $    1.26     $  1.19

    July                           September         $    0.42     $  0.41
    August                         October                0.42        0.43
    September                      November               0.42        0.44(*)
    -------------------------------------------------------------------------
    Third Quarter Total                              $    1.26     $  1.28

    Total Year-to-Date                               $    3.78     $  3.59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Calculated using an exchange rate of 0.95


    2007 Development Activity
    -------------------------

                                3rd Quarter                Year to date
                        -------------------------- --------------------------
                          Capital   Wells Drilled    Capital   Wells Drilled
                         Spending  ---------------   Spending ---------------
    Play Type          ($millions)  Gross     Net ($millions)  Gross     Net
    -------------------------------------------------------------------------

    Shallow Gas & CBM      $ 16.1   102.0    75.1     $ 26.2   167.0   102.3
    Crude Oil
     Waterfloods             12.8    14.0     5.5       39.8    32.0    20.8
    Bakken Oil               21.6    14.0     7.2       92.5    36.0    20.9
    Oil Sands
     (SAGD/Mining)            1.7       -       -       20.8       -       -
    Other Conventional
     Oil & Gas               38.4    54.0    13.4      101.7   152.0    32.6
    -------------------------------------------------------------------------

    Total                  $ 90.6   184.0   101.2     $281.0   387.0   176.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Success Rate To Date: 99%

    Approximately $25 million has been eliminated from our full year capital
development budget primarily in non-operated deep gas, shallow gas and coalbed
methane activities due to lower gas prices and uncertainty around the province
of Alberta's review of its royalty regime. This has impacted our third quarter
volumes by approximately 1,300 BOE/day and our full-year average production by
approximately 600 BOE/day. Although initial production rates on our U.S.
Bakken third well per section program have been lower than anticipated,
recoverable reserves remain in line with expectations and provide attractive
returns. This has contributed to a shortfall in production volumes of
approximately 1,000 BOE/day during the third quarter and will impact our full
year and exit rate volumes by the same amount. Increased downtime and
unplanned turn-around activities at our partner-operated facilities have also
played a role in the lower production volumes realized during the quarter,
accounting for roughly 1,500 BOE/day and will impact our annual average
production by approximately 900 BOE/day. Due to these issues, we are reducing
our annual average production guidance for 2007 by 3% to 82,500 BOE/day with a
revised exit rate of 83,000 BOE/day. Our operating costs per BOE will also be
impacted and are now expected to average $9.20/BOE for 2007.
    With strong crude oil prices supporting robust drilling and development
activity in Canada and the United States, pipeline capacity in growth areas is
becoming constrained. In particular, producers in the Montana, North Dakota
and southeast Saskatchewan producing regions are facing risks of curtailment
until planned capacity expansions are brought on-line. There is potential that
these curtailments could impact both our fourth quarter production and exit
rates.

    OIL SANDS

    Our oil sands business continues to take shape as our Kirby operated
project and our Joslyn non-operated project advance.
    At Joslyn, we have received the initial Norwest mining report on the
Joslyn lease which indicates significantly increased contingent resource under
a 15:1 total volume to bitumen in place ("TV:BIP") ratio. Previously a 12:1
TV:BIP ratio was the accepted standard for oil sands projects but recently a
major oil sands producer has submitted an application with a 16:1 TV:BIP ratio
for an expansion project and now other oil sand participants are considering
this type of higher ratio. The original resource estimate of the Joslyn lease
indicated 223 million barrels of contingent resources based upon a 12:1 TV:BIP
ratio using the best estimates. If developed on a 15:1 TV:BIP ratio,
essentially the entire Joslyn lease would be mineable resulting in increased
recoveries and potentially increased production rates over the current plans
with no expansion of the existing Phase II SAGD project. Our third party
engineering firm will be using the Norwest report to update our resource
estimates for our year-end engineering.
    Although recent operational changes are having positive impacts on
production rates, the Joslyn SAGD project continues to run behind
expectations. A major turnaround of the facility is being completed subsequent
to the quarter and performance of the existing well pairs is being monitored.
There are currently no plans to drill any additional well pairs until at least
2009 nor does the operator expect to achieve commercial production prior to
the 2009 timeframe. Future drilling will be dependent on the extent of the
improved performance from the existing well pairs.
    Full lease development plans are expected in late 2008 after completing
updated engineering and economics around the mining options, assessing SAGD
performance and completing an optimization analysis on various development
options for the lease.
    At Kirby, we expect to begin drilling approximately 80 new core holes on
the Kirby lease this winter and will also be testing for water sources and
disposal zones on the lease. We continue to add to our staff complement, and
are advancing our preliminary engineering as we plan the filing of our
regulatory application in 2008 for our 10,000 bbl/day project.

    ALBERTA ROYALTY REVIEW
    ----------------------
    On October 25, 2007 the Alberta government announced a new oil and gas
royalty framework for the province. This new royalty regime takes effect on
January 1, 2009 and is expected to increase royalties paid by the oil and gas
industry by 20% ($1.4 billion) by 2010, depending upon future prices and
production levels in the province.
    Enerplus currently has approximately 73% of our production derived from
Alberta with roughly 45% of our total royalty expense paid to the Alberta
government. Further details on the Alberta government's new framework are
still to come however at this time, our best estimate of the impact of the new
level of royalties on our conventional business will be approximately $15 -
$20 million annually representing a reduction of approximately 2% to cash flow
within the context of prices and production experienced in 2007. Refer to our
MD&A for further discussion of this issue. With respect to oil sands, based
upon the current commodity price environment, the estimated royalty impact on
both the Kirby and Joslyn projects are essentially offset with the federal
government's plans to reduce tax rates. Therefore we see no change to our
development plans.
    We expect to continue investing in the province of Alberta, but are
reviewing the economics associated with our capital plans and our
opportunities to reallocate additional investment outside of Alberta in light
of the new royalty regime. A portion of our oil and natural gas interests in
Alberta are operated by industry partners and we will be working with those
partners to determine go forward plans on these properties. Given our diverse
asset base, the results of our economic analysis and the response of our
partners, we may shift some of our capital spending to other provinces or the
U.S. in order to maximize our economic returns.


    On October 30, 2007, a NAFTA claim with respect to the Canadian
Government's plan to impose a tax on trusts was put forward by two income
trust unitholders from the United States. The claim challenges the actions of
the Canadian Government and seeks monetary compensation for losses related to
those actions. It is our understanding that all U.S. and Mexican citizens who
held units in a Canadian energy trust on October 31, 2006 may also be eligible
to file a similar claim. Unitholders wishing further information about this
claim and the NAFTA process can visit the following website,
www.NAFTAtrustclaims.com.

    Notwithstanding the challenges we are facing in our industry today, we
fundamentally believe Enerplus is well positioned for the future. Our strong
balance sheet, merger and acquisition capabilities, large inventory of
development prospects and future oil sands opportunities set us apart from
many other oil and gas producers. We will continue to seek out ways to improve
and expand our business and are committed to providing our investors with a
superior return on their investment.

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

    The following discussion and analysis of financial results is dated
November 8, 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
        September 30, 2007 and for the three and nine months ended
        September 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. In addition to disclosing reserves under
the requirements of NI 51-101, we also disclose our reserves on a company
interest basis which is not a term defined under NI 51-101. This information
may not be comparable to similar measures presented by other issuers. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading. 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.

    Alberta Royalty Review

    On October 25, 2007 the Alberta government announced changes to the
provincial royalty program effective January 1, 2009. The government has
introduced dual sliding scale royalties for conventional crude oil and natural
gas production that are based on commodity price levels and monthly well
production rates. Although royalty rates were reduced for certain low
productivity wells in low price environments, most royalties are expected to
increase, especially with higher well productivity and commodity prices. The
Alberta government expects to increase its royalty revenues by 20% or 
$1.4 billion by 2010 as a result of this change in the royalty regime.
    New royalty rates for natural gas wells will range from 5% to 50% of a
market-based reference price, an increase from the current program that ranges
from 5% to 35%. In addition, the government has announced a program whereby
deep gas wells are less affected by the new royalty regime based on a formula
that is sensitive to total drilling distances (both vertical and horizontal)
that exceed 2,000 meters. We also expect a more favorable royalty framework is
forthcoming (lower royalties and a wider price range than other conventional
gas) for coal bed methane, tight gas and shale gas but no specific information
with respect to these royalty programs are available from the government.
    Furthermore on natural gas, the government announced it will implement
"shallow rights reversion" whereby mineral rights to undeveloped shallow gas
above zones that are being developed will revert back to the government and
made available for resale. Enerplus is assessing the potential impact of this
policy on our reserves and development plans pending further details from the
government.
    Royalty rates for crude oil wells will increase from the current maximum
of 35% to a new maximum of 50% for higher ranging prices and production
levels. Most other specialty royalty programs will be eliminated.
    For oil sands, the current base or start-up royalty rate is 1%. Under the
new system the pre-payout rate will start at 1% and increase for oil priced
above $55/bbl to a maximum of 9% when oil is priced at $120/bbl or higher. The
current post-payout royalty rate is 25% for oil sands. Under the new regime,
the post-payout royalty will start at 25% and increase for oil priced above
$55/bbl to a maximum of 40% when oil is priced at $120/bbl or higher. We don't
expect these increases will have a significant impact on our oil sands
projects.
    Details of the new royalty program can be found on the Alberta
government's website at www.gov.ab.ca.
    Approximately $96.0 million (45%) of Enerplus' total royalties during the
nine months ended September 30, 2007 were Alberta crown royalties. We have
attempted to estimate the impact of the royalty changes on Enerplus however
this is difficult as details have yet to be finalized.
    Based on royalties paid during 2007 and in the context of production and
pricing during that period, we would expect Alberta royalties to increase by
approximately $15 to $20 million annually or 2% of operating cash flow and
total royalties to increase by approximately 5% to 7%. Our total consolidated
royalty rate would increase from 19% to approximately 20% of total revenues.
The moderate increase is a reflection of the new royalty regime's sensitivity
to the low natural gas prices experienced this year and Enerplus' portfolio of
lower productivity wells. It is important to note that these estimates have
assumed the applicability of deeper well relief to our current wells and that
the current "corporate effective" royalty rates used to calculate the Crown's
share of capital for gas processing facilities will be similar to the new
"facility effective" rates proposed by the government. Also, these estimates
are based on production and pricing that may not be indicative of the
environment in 2009 when these royalty changes come into effect.
    We have not finalized our 2008 capital budget; however, we expect some
capital spending may be redirected to the U.S., Manitoba, Saskatchewan and
B.C. in pursuit of more attractive economic returns.

    Canadian Government's Tax on Income Trusts

    On June 22, 2007 Bill C-52, which contains legislative provisions to
implement the proposals to tax publicly traded income trusts in Canada became
law. As a result, our year to date 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 remaining
three-year tax exemption period through 2010 and will look to maintain our
current structure during this period unless there are compelling reasons to
change.

    Overview

    During the third quarter we had a modest decrease in cash flow to
$232.8 million from $237.5 million in the second quarter. Our year-to-date
cash flow is consistent with the previous period, however third quarter cash
flow decreased 13% compared to the same period in 2006. Strong crude oil
prices helped to reduce the impact of weak natural gas prices, lower
production and the strengthening Canadian dollar. Overall our production
decreased by 3% from the second quarter to 79,891 BOE/day and development
capital spending totaled $90.6 million for the quarter. Based on our
year-to-date results we are revising our annual development capital spending
guidance down by $25 million to $390 million. We are also decreasing our
average annual production guidance to 82,500 BOE/day and our 2007 exit rate to
83,000 BOE/day. In conjunction with the revised production estimates, we are
increasing our annual operating cost guidance to $9.20/BOE however our general
and administrative expense guidance remains unchanged.
    Despite these challenges, we maintained our monthly distributions at
$0.42 per unit during the third quarter with a payout ratio of 70% and our
debt-to-cash flow remains at a conservative 0.7x (based on trailing twelve
month cash flow).

    Results of Operations

    Production

    Production averaged 79,891 BOE/day during the third quarter of 2007, a
decrease of 3% from 82,478 BOE/day during the second quarter of 2007.
    For the three and nine months ended September 30, 2007 production
decreased by 5% and 3% respectively, compared to the same periods in 2006. The
decrease was due to lower than anticipated initial production rates in the
U.S. and increased downtime and unplanned turn-around activities at partner
operated facilities, partially offset by 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.
    Based on our year-to-date results we are decreasing our annual production
guidance by approximately 3% to 82,500 BOE/day from 85,000 BOE/day and our
2007 exit rate by approximately 3% to 83,000 BOE/day from 86,000 BOE/day. A
$25 million reduction in our annual development capital spending program to
$390 million has decreased our annual production estimate by approximately
600 BOE/day and exit rate estimate by approximately 1,100 BOE/day. Our U.S.
Bakken oil program continues to deliver attractive economics and reserves,
however lower initial production rates have decreased both our annual
production and exit rate estimates by approximately 1,000 BOE/day. Unplanned
turn-around activities primarily at partner-operated facilities and along with
increased downtime in the U.S. and other minor factors have negatively
impacted our annual average and exit rate production by approximately 900
BOE/day.  Although the partner-operated facilities are expected to be back on
line at year-end, the U.S. downtime and other minor factors will continue to
impact our exit rate. Further, there is the potential that pipeline
constraints in Montana, North Dakota and southeast Saskatchewan, resulting
from strong crude oil prices and robust drilling and development activities,
could impact both our fourth quarter production and exit rate.
    Our average production during the third quarter was weighted 52% natural
gas and 48% crude oil and natural gas liquids on a BOE basis. Average
production volumes for the three and nine months ended September 30, 2007 and
2006 are outlined below:

    
                             Three months ended        Nine months ended
                                September 30,             September 30,
    Daily Production                            %                         %
     Volumes                  2007     2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    Natural gas (Mcf/day)  251,264  266,292    (6)%  263,884  268,700    (2)%
    Crude oil (bbls/day)    34,077   35,952    (5)%   34,602   36,065    (4)%
    Natural gas liquids
     (bbls/day)              3,937    4,199    (6)%    4,194    4,487    (6)%
    Total daily sales
     (BOE/day)              79,891   84,533    (5)%   82,777   85,335    (3)%
    -------------------------------------------------------------------------
    

    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 nine months ended September 30, 2007 and 2006.

    
                            Three months ended         Nine months ended
                               September 30,              September 30,
    Average Selling                             %                         %
     Price(1)                2007      2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    Natural gas (per Mcf)  $ 5.59    $ 6.13    (9)%   $ 6.63   $ 6.89    (4)%
    Crude oil (per bbl)    $69.16    $68.57      1%   $62.75   $64.27    (2)%
    Natural gas liquids
     (per bbl)             $50.79    $54.63    (7)%   $49.26   $52.49    (6)%
    Per BOE                $49.64    $51.18    (3)%   $49.89   $51.65    (3)%
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.


                            Three months ended         Nine months ended
                               September 30,              September 30,
    Average Benchmark                           %                         %
     Pricing                 2007      2006  Change     2007     2006  Change
    -------------------------------------------------------------------------
    AECO natural gas -
     monthly index
     (CDN$/Mcf)            $ 5.61    $ 6.03    (7)%   $ 6.81   $ 7.19    (5)%
    AECO natural gas -
     daily index
     (CDN$/Mcf)            $ 5.18    $ 5.64    (8)%     6.55   $ 6.40      2%
    NYMEX natural gas -
     monthly NX3 index
     (US$/Mcf)             $ 6.13    $ 6.53    (6)%   $ 6.88   $ 7.47    (8)%
    NYMEX natural gas -
     monthly NX3 index
     CDN$ equivalent
     (CDN$/Mcf)            $ 6.39    $ 7.34   (13)%   $ 7.56   $ 8.49   (11)%
    WTI crude oil
     (US$/bbl)             $75.38    $70.48      7%   $66.23   $68.22    (3)%
    WTI crude oil CDN$
     equivalent
     (CDN$/bbl)            $78.52    $79.19    (1)%   $72.78   $77.52    (6)%
    US$/CDN$ exchange rate   0.96      0.89      8%     0.91     0.88      3%
    -------------------------------------------------------------------------
    

    We realized an average price on our natural gas of $5.59/Mcf (net of
transportation) during the three months ended September 30, 2007 a decrease of
9% from $6.13/Mcf for the same period in 2006. For the nine months ended
September 30, 2007 our average price of $6.63/Mcf was 4% lower as 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 comparable to the movement of
the benchmark indices as the volume of natural gas sold on each index can vary
each month. Overall our 9% and 4% decreases for the three and nine months
ended September 30, 2007 compared to the same periods in 2006 are fairly
consistent with the fluctuations experienced by the AECO and NYMEX indices.
    The average price we received for our crude oil during the three months
ended September 30, 2007 increased 1% to $69.16/bbl (net of transportation)
from $68.57/bbl during the same period in 2006. The West Texas Intermediate
("WTI") crude oil benchmark price, after adjusting for the change in the US$
exchange rate, decreased 1% from the corresponding period in 2006. For the
nine months ended September 30, 2007 our crude oil price fell 2% relative to
the same period in 2006, while the CDN$ equivalent WTI crude oil benchmark
price fell 6%. This difference was largely due to improved pricing
differentials for our sour and heavy crude oil.
    The Canadian dollar strengthened significantly against the U.S. dollar
during the quarter and the average exchange rates for both the three and nine
month periods in 2007 were also higher than the comparable periods in 2006. At
September 30, 2007 the Canadian dollar was at a thirty year high and at par
with the U.S. dollar. As most of our crude oil and a portion of our 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. For the three months ended September 30, 2007 compared to
September 30, 2006 the WTI price in U.S. dollars increased approximately
$5.00/bbl or 7% but after conversion to Canadian dollars the WTI price
actually decreased by 1%. We expect every $0.01 change in the Canadian/U.S.
dollar exchange rate to impact our annualized cash flow by $0.10 per trust
unit.

    Price Risk Management

    Spot natural gas prices in Alberta were generally in a downtrend during
the quarter influenced by strong production in the U.S., high liquefied
natural gas imports to the U.S. early in the quarter and continued strength in
the Canadian dollar. Prices peaked in August at CDN$5.94/Mcf due to a heat
wave in the U.S. and tropical storm threats, but subsided again going into
September as it became clear that natural gas storage inventories would be
close to capacity by the end of the storage season.
    Global crude oil pricing continued to rise in the third quarter driven by
continued concerns about the supply/demand balance, hurricane season risks,
geopolitical instability and weakness in the U.S. dollar. There was
significant volatility in the quarter with prices moving between US$69.26/bbl
and US$83.32/bbl compared to an opening price of US$71.09/bbl.
    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 third quarter of 2007. We have protected a
portion of our natural gas and crude oil sales for the period October 2007
through December 2009 and have also protected a portion of our exposure to
rising electricity costs in the Alberta power market for the period October
2007 through September 2008. See Note 11 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 October 29, 2007 as a percentage of our forecasted net production
volumes:

    
                                            Natural Gas (CDN$/Mcf)
    -------------------------------------------------------------------------
                                 Oct. 1,     Nov. 1,     Apr. 1,     Nov. 1,
                                   2007-       2007-       2008-       2008-
                                Oct. 31,    Mar. 31,    Oct. 31,    Mar. 31,
                                    2007        2008        2008        2009
    -------------------------------------------------------------------------
    Floor Prices (puts)           $ 7.32      $ 8.12      $ 7.05      $ 7.91
    % (net of royalties)              31%         18%         11%          3%

    Fixed Price (swaps)           $ 7.58      $ 8.81      $ 8.18      $    -
    % (net of royalties)               6%          3%          2%          -%

    Capped Price (calls)          $ 9.07      $10.42      $ 8.43      $10.71
    % (net of royalties)              28%         18%         11%          3%
    -------------------------------------------------------------------------


                                              Crude Oil (US$/bbl)
    -------------------------------------------------------------------------
                                 Oct. 1,     Jan. 1,     Jul. 1,     Jan. 1,
                                   2007-       2008-       2008-       2009-
                                Dec. 31,    Jun. 30,    Dec. 31,    Dec. 31,
                                    2007        2008        2008        2009
    -------------------------------------------------------------------------
    Floor Prices (puts)           $69.89      $70.40      $69.66      $70.00
    % (net of royalties)              39%         31%         26%          4%

    Fixed Price (swaps)           $68.13      $73.52      $73.52      $    -
    % (net of royalties)              11%         11%         11%          -%

    Capped Price (calls)          $84.10      $85.09      $85.09      $85.00
    % (net of royalties)               5%         21%         21%          4%
    -------------------------------------------------------------------------
    Based on weighted average price (before premiums), average annual
    production of 82,500 BOE/day and assuming a 19% royalty rate.
    

    Accounting for Price Risk Management

    During the third quarter of 2007, our commodity price risk management
program generated cash gains of $7.4 million and non-cash losses of
$3.8 million compared to cash losses of $1.1 million and non-cash gains of
$19.1 million during the second quarter of 2007. The increase in cash gains is
due to the impact of lower natural gas prices which more than offset the
impact of higher crude oil prices during the third quarter. The change in
non-cash costs is attributable to the impact of higher forward crude oil
prices on our crude oil positions at the end of the third quarter, partially
offset by the impact of lower forward natural gas prices.
    Our natural gas cash gains for the three months ended September 30, 2007
increased to $14.1 million from $0.5 million for the same period in 2006. For
the nine months ended September 30, 2007 we had a natural gas cash gain of
$12.8 million as compared to $10.1 million in cash losses for the same period
in 2006. These increases in cash gains were due to contracts in place during
2007 that provided floor protection as the price of natural gas declined.
    Compared to the third quarter of 2006 our crude oil cash losses increased
to $6.7 million from $1.3 million. The increase in cash losses is due to crude
oil prices rising above our swap positions. For the nine months ended
September 30, 2007 we had a slight crude oil cash gain of $1.4 million as
compared to cash losses of $30.2 million for the same period in 2006. The cash
losses in 2006 were caused by contracts that had ceiling prices between
US$35.35/bbl and US$45.80/bbl that expired June 30, 2006.
    At September 30, 2007 the fair value of our crude oil derivative
instruments, net of premiums, represents a loss of $14.9 million and is
recorded on our balance sheet as a deferred financial credit. The fair value
of our natural gas derivative instruments, net of premiums, represents a gain
of $20.3 million and is recorded on our balance sheet as a deferred financial
asset. In comparison at December 31, 2006 the fair value of our crude oil
derivative instruments represented a gain of $10.9 million and the fair value
of our natural gas derivative instruments represented a gain of $12.7 million,
both of which were recorded on our balance sheet as a deferred financial
asset. As the forward markets for natural gas and crude oil fluctuate, and new
contracts are executed and existing contracts are realized, changes in fair
value are reflected as a non-cash charge or increase to earnings. These
changes amounted to a $3.8 million loss during the third quarter of 2007 and
an $18.2 million loss during the nine months ended September 30, 2007. 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)             Sept. 30, 2007          Sept. 30, 2006
    -------------------------------------------------------------------------
    Cash (gains)/losses:
      Crude oil                $  6.7    $  2.14/bbl   $  1.3    $  0.39/bbl
      Natural gas               (14.1)   $(0.61)/Mcf     (0.5)   $(0.02)/Mcf
    Total Cash                --------                --------
     (gains)/losses            $ (7.4)   $(1.00)/BOE   $  0.8    $  0.10/BOE

    Non-cash losses/(gains)
     on financial contracts:
      Change in fair value
       -crude oil              $  6.6    $  2.12/bbl   $(23.0)   $(6.96)/bbl
      Change in fair value
       -natural gas              (2.8)   $(0.12)/Mcf     (4.0)   $(0.16)/Mcf
      Amortization of
       deferred financial
       assets                       -    $    - /BOE     10.3    $  1.32/BOE
    Total Non-cash            --------                --------
     losses/(gains)            $  3.8    $  0.51/BOE   $(16.7)   $(2.15)/BOE

                              --------                --------
    Total gains                $ (3.6)   $(0.49)/BOE   $(15.9)   $(2.05)/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Risk Management Costs
     ($ millions, except         Nine months ended       Nine months ended
     per unit amounts)             Sept. 30, 2007          Sept. 30, 2006
    -------------------------------------------------------------------------
    Cash (gains)/losses:
      Crude oil                $ (1.4)   $(0.15)/bbl   $ 30.2    $  3.07/bbl
      Natural gas               (12.8)   $(0.18)/Mcf     10.1    $  0.14/Mcf
    Total Cash                --------                --------
     (gains)/losses            $(14.2)   $(0.63)/BOE   $ 40.3    $  1.73/BOE

    Non-cash losses/(gains)
     on financial contracts:
      Change in fair value
       -crude oil              $ 25.8    $  2.74/bbl   $(42.5)   $(4.32)/bbl
      Change in fair value
       -natural gas              (7.6)   $(0.11)/Mcf    (47.0)   $(0.64)/Mcf
      Amortization of
       deferred financial
       assets                       -    $    - /BOE     47.0    $  2.02/BOE
    Total Non-cash            --------                --------
     losses/(gains)            $ 18.2    $  0.81/BOE   $(42.5)   $(1.82)/BOE

                              --------                --------
    Total losses/(gains)       $  4.0    $  0.18/BOE   $ (2.2)   $(0.09)/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Revenues

    Crude oil and natural gas revenues during the third quarter of 2007 were
lower than the second quarter of 2007 as improved crude oil prices were more
than offset by the impact of lower production and natural gas prices.
    Crude oil and natural gas revenues for the three months ended
September 30, 2007 were $364.8 million ($370.2 million, net of $5.4 million
transportation) compared to $398.0 million ($403.7 million, net of
$5.7 million transportation) for the same period in 2006. For the nine months
ended September 30, 2007 revenues were $1,127.3 million ($1,144.0 million, net
of $16.7 million transportation) compared to $1,203.2 million
($1,220.7 million, net of $17.5 million transportation) during the same period
in 2006.
    The decrease in revenues of $33.2 million or 8% for the three months
ended September 30, 2007 and $75.9 million or 6% for the nine months ended
September 30, 2007 compared to the same periods in 2006 was due to decreased
production and lower realized commodity prices.

    The following table summarizes the changes in sales revenue:

    
    -------------------------------------------------------------------------
    Analysis of Sales Revenue(1)                          Natural
    ($ millions)                  Crude Oil       NGLs        Gas      Total
    -------------------------------------------------------------------------
    Quarter ended
     September 30, 2006            $  226.8   $   21.1   $  150.1   $  398.0
    Price variance(1)                   1.8       (1.4)     (12.0)     (11.6)
    Volume variance                   (11.8)      (1.3)      (8.5)     (21.6)
    -------------------------------------------------------------------------
    Quarter ended
     September 30, 2007            $  216.8   $   18.4   $  129.6   $  364.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                                          Natural
    ($ millions)                  Crude Oil       NGLs        Gas      Total
    -------------------------------------------------------------------------
    Year-to-date ended
     September 30, 2006            $  632.7   $   64.3   $  506.2   $1,203.2
    Price variance(1)                 (14.4)      (3.7)     (18.9)     (37.0)
    Volume variance                   (25.6)      (4.2)      (9.1)     (38.9)
    -------------------------------------------------------------------------
    Year-to-date ended
     September 30, 2007            $  592.7   $   56.4   $  478.2   $1,127.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    

    Other Income

    Other income for the three and nine months ended September 30, 2007 was
$0.1 million and $14.6 million, respectively, compared to $1.1 million and
$2.4 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 nine months ended September 30, 2007
royalties were $68.2 million and $211.9 million, respectively, both
approximately 19% of oil and gas sales, net of transportation. For the three
and nine months ended September 30, 2006 royalties were $70.9 million and
$230.3 million, approximately 18% and 19% of oil and gas sales, net of
transportation, respectively. The decrease in royalties for the three and nine
months ended September 30, 2007 compared to the same periods in 2006 is a
result of lower natural gas prices.
    For 2007 we expect royalties to be approximately 19% of oil and gas
sales, net of transportation costs.
    As mentioned at the beginning of this MD&A, the Alberta government
announced changes to the province's oil and gas royalty regime. Alberta Crown
royalties represented approximately 45% of total royalties incurred during the
nine months ended September 30, 2007.

    Operating Expenses

    Operating expenses during the third quarter of 2007 were $9.73/BOE which
was consistent with the second quarter costs of $9.69/BOE.
    Operating expenses for the three months ended September 30, 2007 were
$71.6 million or $9.73/BOE compared to $59.7 million or $7.68/BOE for the
third quarter of 2006. For the nine months ended September 30, 2007 operating
costs were $210.3 million or $9.31/BOE compared to $183.0 million or $7.85/BOE
for the same period in 2006. We have experienced higher costs for well
servicing, labour, supplies, and repairs and maintenance associated with
unplanned turnaround activities during the quarter. Furthermore, we continue
to implement our field training initiative focused on improving operating
results over the long-term. Lower production volumes compared to 2006 have
also contributed to the cost increase on a dollar per BOE basis.
    As a result of our lower annual production forecast, we are revising our
operating cost guidance to approximately $9.20/BOE for 2007.

    General and Administrative Expenses

    General and administrative ("G&A") expenses for the third quarter of 2007
were 6% higher than the second quarter of 2007.
    G&A expenses for the three months ended September 30, 2007 were
$17.7 million or $2.41/BOE compared to $15.0 million or $1.93/BOE for the
third quarter of 2006. G&A expenses totaled $51.5 million or $2.28/BOE for the
nine months ended September 30, 2007 compared to $42.9 million or $1.84/BOE
for the same period in 2006. The year-over-year increase is primarily due to
compensation costs and is in line with our expectations for 2007.
    For the three and nine months ended September 30, 2007 our G&A expenses
included non-cash charges of $2.2 million or $0.30/BOE and $6.4 million or
$0.28/BOE respectively, compared to $1.8 million or $0.23/BOE and $4.3 million
or $0.18/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    Nine months ended
     Costs                             September 30,         September 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash                           $   15.5   $   13.2   $   45.1   $   38.6
    Non-cash trust unit rights
     incentive plan                     2.2        1.8        6.4        4.3
    -------------------------------------------------------------------------
    Total G&A                      $   17.7   $   15.0   $   51.5   $   42.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (Per BOE)
    -------------------------------------------------------------------------
    Cash                           $   2.11   $   1.70   $   2.00   $   1.66
    Non-cash trust unit rights
     incentive plan                    0.30       0.23       0.28       0.18
    -------------------------------------------------------------------------
    Total G&A                      $   2.41   $   1.93   $   2.28   $   1.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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 includes interest on long-term debt, the amortization of
the premium on our US$175 million senior unsecured notes, and unrealized gains
and losses resulting from the change in fair value of our interest rate swaps
as well as the interest component on our cross currency interest rate swap
("CCIRS"). See Note 9 for more details.
    Interest expense in the third quarter of 2007 was $6.4 million or 46%
lower than the second quarter of 2007 due to changes in the fair value of our
interest rate swaps and CCIRS. The third quarter of 2007 included an
unrealized gain of $4.0 million whereas the second quarter of 2007 included an
unrealized loss of $2.1 million. After adjusting for these unrealized amounts,
interest on long-term debt for the third quarter of 2007 was comparable to the
second quarter of 2007.
    Interest on long-term debt for the three and nine months ended
September 30, 2007 was $10.4 million and $29.8 million compared to $8.6
million and $23.6 million for the same periods in 2006. These increases are
due to higher average indebtedness and interest rates during 2007.
    Unrealized gains during the three and nine months ended September 30,
2007 were $4.0 million and $3.4 million. The unrealized gain for the quarter
results mainly from the change in fair value of the interest component on our
CCIRS while the unrealized gain for the nine months results from the change in
fair value of the interest component on our CCIRS and our interest rate swaps.

    The following table summarizes the cash and non-cash interest expense
recorded.

    
                                   Three months ended     Nine months ended
    Interest Expense                  September 30,         September 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Interest on long-term debt     $   10.4   $    8.6   $   29.8   $   23.6
    Unrealized gain                    (4.0)         -       (3.4)         -
    -------------------------------------------------------------------------
    Total Interest Expense         $    6.4   $    8.6   $   26.4   $   23.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

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

    Capital Expenditures

    We spent $90.6 million and $281.0 million on development drilling and
facilities for the three and nine months ended September 30, 2007
respectively, compared to $131.7 million and $368.1 million during the same
periods in 2006. We achieved a 99% success rate with our third quarter
drilling program as 101.2 net wells were drilled. Year-to-date, 176.6 net
wells were drilled compared to 304.3 in 2006. Development in 2007 continues to
focus primarily on Sleeping Giant Bakken oil and crude oil waterfloods. The
reduction in the total number of wells drilled in 2007 compared to 2006
reflects more high cost oil wells being drilled in 2007 compared to low cost
shallow gas wells in 2006 and the deferral of several natural gas projects
into 2008.
    Property acquisitions were $1.8 million and $269.1 million for the three
and nine months ended September 30, 2007, compared to $4.3 million and
$46.5 million for the same periods in 2006. During the second quarter of 2007
we acquired the Kirby Oil Sands Partnership ("Kirby") for total consideration
of $203.1 million. During the first quarter of 2007 we acquired Jonah for
total consideration of approximately $61 million.
    Property dispositions were $0.1 million and $5.5 million for the three
and nine months ended September 30, 2007 compared to $0.2 million and
$21.0 million for the same periods in 2006. The majority of the $21.0 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     Nine months ended
    Capital Expenditures              September 30,         September 30,
     ($ millions)                      2007       2006       2007       2006
    -------------------------------------------------------------------------
    Development expenditures       $   72.1   $   96.0   $  232.3   $  284.0
    Plant and facilities               18.5       35.7       48.7       84.1
    -------------------------------------------------------------------------
      Development Capital              90.6      131.7      281.0      368.1
    Office                              1.7        1.0        4.6        2.3
    -------------------------------------------------------------------------
      Sub-total                        92.3      132.7      285.6      370.4
    Acquisitions of oil and gas
     properties(1)                      1.8        4.3      269.1       46.5
    Dispositions of oil and gas
     properties(1)                     (0.1)      (0.2)      (5.5)     (21.0)
    -------------------------------------------------------------------------
    Total Net Capital
     Expenditures                  $   94.0   $  136.8   $  549.2   $  395.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total Capital Expenditures
     financed with cash flow       $   69.7   $  114.2   $  180.1   $  197.3
    Total Capital Expenditures
     financed with debt and equity     24.3       22.6      369.1      218.1
    Total non-cash consideration
     for 1% sale of Joslyn project        -          -          -      (19.5)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures $   94.0   $  136.8   $  549.2   $  395.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of post-closing adjustments.
    

    Due to the delays in our capital program to date and the deferral of
several natural gas projects into 2008 in areas such as Elmworth, Ferrier,
Shackleton and Joffre, we are revising our 2007 annual development capital
spending guidance down by $25 million to $390 million.

    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 and nine months ended September 30, 2007, DDA&A was
$15.78/BOE and $15.58/BOE compared to $16.64/BOE and $15.54/BOE during the
corresponding period in 2006. Although the depletion rate for the third
quarter of 2006 was higher than trend, the full year annual rate for 2006 was
$15.38/BOE, which is comparable to our depletion rates during 2007.
    No impairment of the Fund's assets existed at September 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     Nine months ended
                                      September 30,         September 30,
    ($ millions)                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Amortization of the asset
     retirement cost               $    3.4   $    3.3   $    6.9   $    9.4
    Accretion of the asset
     retirement obligation              1.7        1.6        5.0        4.6
    -------------------------------------------------------------------------
    Total Amortization and
     Accretion                     $    5.1   $    4.9   $   11.9   $   14.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Asset Retirement Obligations
     Settled                       $    3.5   $    1.6   $   10.7   $    7.2
    -------------------------------------------------------------------------
    

    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.
    With the enactment of the tax on distributions from publicly traded
income trusts and limited partnerships ("SIFT tax") during the second quarter
of 2007, all entities within our organization are now subject to future income
taxes whereas prior to the SIFT tax enactment only incorporated entities in
our organization were subject to future income taxes. As a result our future
income tax recovery was $8.8 million for the three months ended September 30,
2007 compared to a recovery of $32.3 million for the same period in 2006. For
the nine months ended September 30, 2007 a future income tax expense of
$38.4 million was recorded in income compared to a future income tax recovery
of $78.9 million during the same period in 2006. The changes in future income
taxes for the nine months ended September 30, 2007 compared to the same period
in 2006 are primarily a result of the following:

    
    -   The 31.5% SIFT tax will be applicable to the Fund effective
        January 1, 2011 provided that we remain a trust and comply with the
        "normal growth" guidelines regarding equity capital as outlined by
        the government. This change resulted in a future income tax expense
        of $78.1 million 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.
    On October 30, 2007 the Federal Government announced its fall economic
statement ("mini-budget"). The mini-budget proposes to cut the general
corporate tax rate by 1% in 2008 from 20.5% to 19.5%. There are additional
rate reductions scheduled until the target federal tax rate of 15% is reached
as of January 1, 2012. These rate reductions will also apply to the SIFT tax
on distributions from income trusts. If the tax rate reductions are enacted as
presented, the SIFT tax rate will fall by 3.5% from 31.5% to 28%.
    If the mini-budget proposals become substantially enacted, we would
record a future income tax recovery, however at this time we are unable to
determine when or if the mini-budget proposals will become substantively
enacted.

    Current Income Taxes

    In our current structure, payments are made between the operating
entities and the Fund which ultimately transfers both income and future income
tax liability to our unitholders. As a result, no cash income taxes have been
paid by our Canadian operating entities. However, effective January 1, 2011 we
will be subject to the SIFT tax at a rate of 31.5% should we remain a trust.
    For the three and nine months ended September 30, 2007 our U.S.
operations incurred current taxes in the amounts of $5.1 million and
$10.4 million respectively, compared to $3.1 million and $13.1 million during
the same periods in 2006. The increase in current taxes in the three months
ended September 30, 2007 is due to a decrease in drilling and completion
expenditures incurred in the period. However there is a decrease in current
taxes for the nine months ended September 30, 2007 due to an increase in
drilling and completion expenditures year-to-date.
    The amount of current taxes recorded throughout the year is dependent
upon the timing of both capital expenditures and repatriation of the funds to
Canada. We now expect current income and withholding taxes to be approximately
10% of cash flow from U.S. operations in 2007 assuming all funds available
after U.S. development capital spending are repatriated to Canada compared to
our previous estimate of 15%.

    Net Income

    Net income for the third quarter of 2007 was $93.0 million or $0.72 per
trust unit compared to $161.3 million or $1.31 per trust unit for the third
quarter of 2006. Net income for the nine months ended September 30, 2007 was
$241.0 million or $1.90 per trust unit compared to $434.6 million or $3.59 per
trust unit for the same period in 2006. The decrease during the three and nine
months ended September 30, 2007 is due to increased future income tax expense
(or reduced recovery) resulting from the SIFT tax enactment, lower oil and gas
sales and increased operating and G&A costs, partially offset by lower
royalties and depletion expense.

    Cash Flow from Operating Activities

    Cash flow for the three and nine months ended September 30, 2007 was
$232.8 million and $663.5 million respectively, compared to $268.9 million and
$656.6 million for the three and nine months ended September 30, 2006. For the
quarter, this decrease was primarily a result of lower oil and gas sales and
higher operating costs. For the nine months ended September 30, 2007 cash flow
was consistent with the same period in 2006.

    Selected Financial Results

    
                       Three months ended            Three months ended
                       September 30, 2007            September 30, 2006
    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
     production       Cash   & Other                Cash   & Other
     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
    -------------------------------------------------------------------------
    Production
     per day                            79,891                        84,533
    -------------------------------------------------------------------------
    Weighted
     average
     sales
     price(2)      $ 49.64   $     -   $ 49.64   $ 51.18   $     -   $ 51.18
    Royalties        (9.28)        -     (9.28)    (9.12)        -     (9.12)
    Commodity
     derivative
     instruments      1.00     (0.51)     0.49     (0.10)     2.15      2.05
    Operating
     costs           (9.61)    (0.12)    (9.73)    (7.68)        -     (7.68)
    General and
     administrative  (2.11)    (0.30)    (2.41)    (1.70)    (0.23)    (1.93)
    Interest
     expense, net
     of interest
     income          (1.40)     0.54     (0.86)    (0.96)        -     (0.96)
    Foreign
     exchange
     gain/(loss)      0.06      0.03      0.09      0.08         -      0.08
    Current
     income tax      (0.70)        -     (0.70)    (0.40)        -     (0.40)
    Restoration
     and
     abandonment
     cash costs      (0.48)     0.48         -     (0.21)     0.21         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (15.78)   (15.78)        -    (16.64)   (16.64)
    Future income
     tax (expense)/
     recovery            -      1.20      1.20         -      4.16      4.16
    -------------------------------------------------------------------------
    Total per BOE  $ 27.12   $(14.46)  $ 12.66   $ 31.09   $(10.35)  $ 20.74
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.


                        Nine months ended             Nine months ended
                       September 30, 2007            September 30, 2006
    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
     production       Cash   & Other                Cash   & Other
     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
    -------------------------------------------------------------------------
    Production
     per day                            82,777                        85,335
    -------------------------------------------------------------------------
    Weighted
     average
     sales
     price(2)      $ 49.89   $     -   $ 49.89   $ 51.65   $     -   $ 51.65
    Royalties        (9.38)        -     (9.38)    (9.89)        -     (9.89)
    Commodity
     derivative
     instruments      0.63     (0.81)    (0.18)    (1.73)     1.82      0.09
    Operating
     costs           (9.32)     0.01     (9.31)    (7.85)        -     (7.85)
    General and
     administrative  (2.00)    (0.28)    (2.28)    (1.66)    (0.18)    (1.84)
    Interest
     expense, net
     of interest
     income          (1.29)     0.15     (1.14)    (0.91)        -     (0.91)
    Foreign
     exchange
     gain/(loss)     (0.05)     0.23      0.18         -      0.12      0.12
    Current
     income tax      (0.46)        -     (0.46)    (0.56)        -     (0.56)
    Restoration
     and
     abandonment
     cash costs      (0.47)     0.47         -     (0.31)     0.31         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (15.58)   (15.58)        -    (15.54)   (15.54)
    Future income
     tax (expense)/
     recovery            -     (1.70)    (1.70)        -      3.39      3.39
    Gain on sale
     of marketable
     securities(3)       -      0.62      0.62         -         -         -
    -------------------------------------------------------------------------
    Total per BOE  $ 27.55   $(16.89)  $ 10.66   $ 28.74   $(10.08)  $ 18.66
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 nine months ended September 30, 2007 and
2006.

    
                                                    Three months ended
                                                    September 30, 2007
    (CDN$ millions, except per unit amounts)    Canada       U.S.      Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    241,196     10,068    251,264
      Crude oil (bbls/day)                      24,236      9,841     34,077
      Natural gas liquids (bbls/day)             3,937          -      3,937
      Total daily sales (BOE/day)               68,372     11,519     79,891

    Pricing(1)
      Natural gas (per Mcf)                    $  5.58    $  5.67    $  5.59
      Crude oil (per bbl)                      $ 65.78    $ 77.49    $ 69.16
      Natural gas liquids (per bbl)            $ 50.79    $     -    $ 50.79

    Capital Expenditures
      Development capital and office           $  70.5    $  21.8    $  92.3
      Acquisitions of oil and gas properties   $   1.8    $     -    $   1.8
      Dispositions of oil and gas properties   $  (0.1)   $     -    $  (0.1)

    Revenues
      Oil and gas sales(1)                     $ 289.4    $  75.4    $ 364.8
      Royalties                                $ (52.6)   $ (15.6)(2)$ (68.2)
      Commodity derivative instruments         $   3.6    $     -    $   3.6

    Expenses
      Operating                                $  68.9    $   2.7    $  71.6
      General and administrative               $  16.3    $   1.4    $  17.7
      Depletion, depreciation, amortization
       and accretion                           $  88.9    $  27.1    $ 116.0
      Current income taxes                     $     -    $   5.1    $   5.1
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.


                                                    Three months ended
                                                    September 30, 2006
    (CDN$ millions, except per unit amounts)    Canada       U.S.      Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    260,381      5,911    266,292
      Crude oil (bbls/day)                      25,288     10,664     35,952
      Natural gas liquids (bbls/day)             4,199          -      4,199
      Total daily sales (BOE/day)               72,884     11,649     84,533

    Pricing(1)
      Natural gas (per Mcf)                    $  6.09    $  7.69    $  6.13
      Crude oil (per bbl)                      $ 66.28    $ 74.00    $ 68.57
      Natural gas liquids (per bbl)            $ 54.63    $     -    $ 54.63

    Capital Expenditures
      Development capital and office           $  99.0    $  33.7    $ 132.7
      Acquisitions of oil and gas properties   $   3.6    $   0.7    $   4.3
      Dispositions of oil and gas properties   $  (0.2)   $     -    $  (0.2)

    Revenues
      Oil and gas sales(1)                     $ 321.2    $  76.8    $ 398.0
      Royalties                                $ (56.2)   $ (14.7)(2)$ (70.9)
      Commodity derivative instruments         $  15.9    $     -    $  15.9

    Expenses
      Operating                                $  57.6    $   2.1    $  59.7
      General and administrative               $  12.1    $   2.9    $  15.0
      Depletion, depreciation, amortization
       and accretion                           $  98.3    $  31.1    $ 129.4
      Current income taxes                     $     -    $   3.1    $   3.1
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.



                                                     Nine months ended
                                                    September 30, 2007
    (CDN$ millions, except per unit amounts)    Canada       U.S.      Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    253,698     10,186    263,884
      Crude oil (bbls/day)                      24,705      9,897     34,602
      Natural gas liquids (bbls/day)             4,194          -      4,194
      Total daily sales (BOE/day)               71,182     11,595     82,777

    Pricing (1)
      Natural gas (per Mcf)                    $  6.63    $  6.78    $  6.63
      Crude oil (per bbl)                      $ 60.06    $ 69.45    $ 62.75
      Natural gas liquids (per bbl)            $ 49.26    $     -    $ 49.26

    Capital Expenditures
      Development capital and office           $ 193.1    $  92.5    $ 285.6
      Acquisitions of oil and gas properties   $ 208.3    $  60.8    $ 269.1
      Dispositions of oil and gas properties   $  (5.6)   $     -    $  (5.6)

    Revenues
      Oil and gas sales(1)                     $ 920.8    $ 206.5    $1,127.3
      Royalties                                $(170.2)   $(41.7)(2) $(211.9)
      Commodity derivative instruments         $  (4.1)   $    -     $  (4.1)

    Expenses
      Operating                                $ 203.3    $  7.0     $ 210.3
      General and administrative               $  46.1    $  5.4     $  51.5
      Depletion, depreciation, amortization
       and accretion                           $ 269.9    $ 82.1     $ 352.0
      Current income taxes                     $     -    $ 10.4     $  10.4
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.


                                                     Nine months ended
                                                    September 30, 2006
    (CDN$ millions, except per unit amounts)    Canada       U.S.      Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                    262,983      5,717    268,700
      Crude oil (bbls/day)                      25,843     10,222     36,065
      Natural gas liquids (bbls/day)             4,487          -      4,487
      Total daily sales (BOE/day)               74,160     11,175     85,335

    Pricing(1)
      Natural gas (per Mcf)                    $  6.86    $  8.16    $  6.89
      Crude oil (per bbl)                      $ 61.72    $ 70.71    $ 64.27
      Natural gas liquids (per bbl)            $ 52.49    $     -    $ 52.49

    Capital Expenditures
      Development capital and office           $ 281.8    $  88.6    $ 370.4
      Acquisitions of oil and gas properties   $  31.2    $  15.3    $  46.5
      Dispositions of oil and gas properties   $ (21.0)   $     -    $ (21.0)

    Revenues
      Oil and gas sales(1)                     $ 993.1    $ 210.1    $1,203.2
      Royalties                                $(190.3)   $(40.0)(2) $(230.3)
      Commodity derivative instruments         $   2.2    $     -    $   2.2

    Expenses
      Operating                                $ 177.5    $   5.5    $ 183.0
      General and administrative               $  37.8    $   5.1    $  42.9
      Depletion, depreciation, amortization
       and accretion                           $ 276.3    $  85.8    $ 362.1
      Current income taxes                     $     -    $  13.1    $  13.1
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.
    

    Quarterly Financial Information - 2005 to 2007

    Oil and gas sales for the third quarter of 2007 were lower than the first
and second quarters of 2007 mainly due to lower production and lower natural
gas prices. 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 third quarter of 2007 was consistent with net income
for the first quarter of 2007 and higher than net income in the second quarter
mainly due to the 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
    Third Quarter                  $  364.8   $   93.0   $   0.72   $   0.72
    Second Quarter                    382.5       40.1       0.31       0.31
    First Quarter                     380.0      107.9       0.88       0.87
    -------------------------------------------------------------------------
    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 producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future oil and natural gas production 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 third quarter of 2007
cash distributions of $163.1 million were funded entirely through cash flow of
$232.8 million. The payout ratio was 70% for the three months ended
September 30, 2007 compared to 58% for the same period in 2006. For the nine
months ended September 30, 2007 our cash distributions were $483.4 million and
were funded entirely through cash flow of $663.5 million. The payout ratio for
the nine months ended September 30, 2007 was 73% compared to 70% for the nine
months ended September 30, 2006.
    After consideration of cash distributions, the balance of our third
quarter cash flow of $69.7 million was used to fund 77% of our $90.6 million
in development capital spending. The balance of our development capital
expenditures and our property acquisitions were financed through a combination
of debt and our distribution reinvestment program.
    In aggregate, our 2007 third quarter cash distributions of $163.1 million
and our development capital spending of $90.6 million totaled $253.7 million,
or approximately 109% of our cash flow of $232.8 million. For the nine months
ended September 30, 2007 our cash distributions of $483.4 million and our
development capital spending of $281.0 million totaled $764.4 million, or
approximately 115% of our cash flow of $663.5 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, 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. It is not possible to distinguish
between capital spent on maintaining productive capacity and capital spent on
growth opportunities in the oil and gas sector due to the nature of reserve
reporting, natural reservoir declines and the risks involved with capital
investment. Therefore we do not disclose maintenance capital separate from
development capital spending.
    For the three months ended September 30, 2007 our cash distributions
exceeded our net income by $70.1 million (2006 - cash distributions
$6.6 million lower than net income) however net income includes $109.9 million
of non-cash items (2006 - $82.1 million) that do not impact our cash flow. For
the nine months ended September 30, 2007 our cash distributions exceeded our
net income by $242.4 million (2006 - $24.7 million) which includes
$406.4 million of non-cash items (2006 - $242.3 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     Nine months ended
    ($ millions, except               September 30,         September 30,
     per unit amounts)                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities:                   $  232.8   $  268.9   $  663.5   $  656.6

    Use of cash flow:
      Cash distributions           $  163.1   $  154.7   $  483.4   $  459.3
      Capital expenditures             69.7      114.2      180.1      197.3
    -------------------------------------------------------------------------
                                   $  232.8   $  268.9   $  663.5   $  656.6

    Excess of cash flow over
     cash distributions            $   69.7   $  114.2   $  180.1   $  197.3

    Net income                     $   93.0   $  161.3   $  241.0   $  434.6
    (Shortfall)/excess of net
     income over cash
     distributions                 $  (70.1)  $    6.6   $ (242.4)  $  (24.7)

    Cash distributions per
     weighted average trust unit   $   1.26   $   1.26   $   3.81   $   3.79
    Payout ratio(1)                      70%        58%        73%        70%
    -------------------------------------------------------------------------
    (1) Based on cash distributions divided by cash flow from operating
        activities.
    

    Long-Term Debt

    Long-term debt at September 30, 2007 which was comprised of
$421.0 million of bank indebtedness and $231.4 million of senior unsecured
notes, decreased to $652.4 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
$32.7 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. dollar
denominated senior notes.
    Subsequent to September 30, 2007 we extended our bank credit facility by
one year to November 2010. In addition, the facility size was increased to
$1.0 billion and there were no changes to the floating interest rates under
the facility.
    We continue to maintain a conservative balance sheet with a long-term
debt to trailing cash flow ratio of 0.7x times as demonstrated below:

    
                                                  September 30,  December 31,
    Financial Leverage and Coverage                       2007          2006
    -------------------------------------------------------------------------
    Long-term debt to trailing cash flow                  0.7x          0.8x
    Cash flow to interest expense                        24.9x         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.
    

    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 September 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 for the remainder of 2007 through a
combination of cash flow retained by the business and debt.

    Foreign Exchange Swaps

    Our US$54 million debentures, which were entered into on October 1, 2003
at a CAD/US$ exchange rate of 1.35, require principal repayments in five equal
installments beginning on October 1, 2011 and ending October 2015. As a result
of the strengthening Canadian dollar against the U.S. dollar, we entered into
foreign exchange swaps during the quarter which effectively fix the principal
repayments at a CAD/US$ exchange rate of 1.02 and secures an economic gain of
$17.9 million. For accounting purposes these swaps have been designated as
held for trading and are recorded on the balance sheet at fair value with the
non-cash changes in fair value recorded in earnings. We will continue to
record the US$54 million debentures on our balance sheet at the period end
foreign exchange rate with the non-cash change recorded in earnings. As the
principal repayments occur and the foreign exchange swaps mature the realized
cash gain or loss at each payment date will be recorded through earnings and
the corresponding non-cash gain or loss will reverse through earnings.

    Commitments

    Subsequent to September 30, 2007, Enerplus extended its bank credit
facility by one year to November 2010 and increased the facility size to
$1.0 billion. Enerplus also extended the Canadian office lease from December
2009 to November 2014. Annual costs of this lease extension, including
operating fees, are approximately $10.7 million annually for a total
additional commitment of approximately $53.6 million.

    Trust Unit Information

    We had 129,552,000 trust units outstanding at September 30, 2007 compared
to 122,854,000 trust units at September 30, 2006 and 123,151,000 at
December 31, 2006. The weighted average basic number of trust units
outstanding for the nine months ended September 30, 2007 was 127,031,000 (2006
- 121,120,000). At November 7, 2007 we had 129,634,000 trust units
outstanding.
    For the three months ended September 30, 2007, 347,000 trust units (2006
- 272,000) were issued pursuant to the Trust Unit Monthly Distribution
Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights plan.
This resulted in $15.1 million (2006 - $13.7 million) of additional equity for
the Fund. During the nine months ended September 30, 2007, 1,046,000 trust
units ($46.8 million additional equity) were issued pursuant to DRIP and the
trust unit options and rights plans compared to 945,000 trust units
($41.7 million) during the same period in 2006. For further details see Note
10.
    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 October 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 entity's
capital and how it is managed. The standard requires qualitative information
about an entity's objectives, policies and processes for managing capital and
quantitative data about what the entity regards as capital. It requires
disclosure of compliance with any capital requirements and consequences of any
non-compliance.
    This standard is effective for 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 September 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 ratio; 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)                               September 30, December 31,
     (Unaudited)                                           2007         2006
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash                                          $     2,570  $       124
      Accounts receivable                               135,918      175,454
      Deferred financial assets (Note 3)                 21,834       23,612
      Other current                                       3,908        6,715
    -------------------------------------------------------------------------
                                                        164,230      205,905
    Property, plant and equipment (Note 4)            3,834,212    3,726,097
    Goodwill                                            196,336      221,578
    Other assets (Note 11)                               58,402       50,224
    -------------------------------------------------------------------------
                                                    $ 4,253,180  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable                              $   270,194  $   284,286
      Distributions payable to unitholders               54,413       51,723
      Deferred financial credits (Note 3)               112,244            -
    -------------------------------------------------------------------------
                                                        436,851      336,009
    -------------------------------------------------------------------------
    Long-term debt (Note 7)                             652,399      679,774
    Future income taxes                                 342,750      331,340
    Asset retirement obligations (Note 6)               124,511      123,619
    -------------------------------------------------------------------------
                                                      1,119,660    1,134,733
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 10)                    4,020,597    3,713,126
    Accumulated deficit                              (1,219,207)    (971,085)
    Accumulated other comprehensive loss (Note 2)      (104,721)      (8,979)
    -------------------------------------------------------------------------
                                                      2,696,669    2,733,062
    -------------------------------------------------------------------------
                                                    $ 4,253,180  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

                                Three months ended         Nine months ended
    (CDN$ thousands)                  September 30,             September 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Accumulated income,
     beginning of period  $ 2,095,193  $ 1,681,484  $ 1,952,960  $ 1,408,178
    Adjustment for
     adoption of
     financial
     instruments
     standards (Note 2)             -            -       (5,724)           -
    -------------------------------------------------------------------------
    Revised Accumulated
     income, beginning
     of period              2,095,193    1,681,484    1,947,236    1,408,178
    Net income                 93,033      161,317      240,990      434,623
    -------------------------------------------------------------------------
    Accumulated income,
     end of period        $ 2,188,226  $ 1,842,801  $ 2,188,226  $ 1,842,801

    Accumulated cash
     distributions,
     beginning of period  $(3,244,323) $(2,614,298) $(2,924,045) $(2,309,705)
    Cash distributions       (163,110)    (154,700)    (483,388)    (459,293)
    -------------------------------------------------------------------------
    Accumulated cash
     distributions, end
     of period            $(3,407,433) $(2,768,998) $(3,407,433) $(2,768,998)

    -------------------------------------------------------------------------
    Accumulated deficit,
     end of period        $(1,219,207) $  (926,197) $(1,219,207) $  (926,197)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

                                Three months ended         Nine months ended
    (CDN$ thousands)               September 30,             September 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Balance, beginning
     of period            $   (65,378) $   (39,217) $    (8,979) $   (15,568)
      Transition
       adjustments(Note 2):
        Cash flow hedges            -            -          660            -
        Available for sale
         marketable
         securities                 -            -       14,252            -
    Other comprehensive
     (loss)/income            (39,343)         978     (110,654)     (22,671)
    -------------------------------------------------------------------------
    Balance, end of
     period               $  (104,721) $   (38,239) $  (104,721) $   (38,239)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF INCOME

    (CDN$ thousands
     except per trust           Three months ended         Nine months ended
     unit amounts)                 September 30,             September 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Revenues
      Oil and gas sales   $   370,163  $   403,761  $ 1,143,960  $ 1,220,677
      Royalties               (68,165)     (70,931)    (211,927)    (230,320)
      Commodity
       derivative
       instruments
       (Notes 3 and 11)         3,585       15,911       (4,067)       2,179
      Other income
       (Note 11)                  143        1,085       14,575        2,375
    -------------------------------------------------------------------------
                              305,726      349,826      942,541      994,911
    -------------------------------------------------------------------------
    Expenses
      Operating                71,551       59,689      210,337      182,960
      General and
       administrative
       (Note 10)               17,718       14,997       51,488       42,862
      Transportation            5,334        5,728       16,651       17,455
      Interest (Note 9)         6,438        8,586       26,400       23,592
      Foreign exchange
       (Note 8)                  (643)        (639)      (4,117)      (2,893)
      Depletion,
       depreciation,
       amortization and
       accretion              116,001      129,400      352,001      362,134
    -------------------------------------------------------------------------
                              216,399      217,761      652,760      626,110
    -------------------------------------------------------------------------
    Income before taxes        89,327      132,065      289,781      368,801
    Current taxes               5,081        3,092       10,372       13,101
    Future income tax
     (recovery)/expense        (8,787)     (32,344)      38,419      (78,923)
    -------------------------------------------------------------------------
    Net Income            $    93,033  $   161,317  $   240,990  $   434,623
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per
     trust unit
      Basic               $      0.72  $      1.31  $      1.90  $      3.59
      Diluted             $      0.72  $      1.31  $      1.90  $      3.58
    -------------------------------------------------------------------------
    Weighted average
     number of trust
     units outstanding
     (thousands)
      Basic                   129,373      122,712      127,031      121,120
      Diluted                 129,402      123,126      127,089      121,511
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                Three months ended         Nine months ended
    (CDN$ thousands)               September 30,             September 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Net income            $    93,033  $   161,317  $   240,990  $   434,623
    -------------------------------------------------------------------------

    Other comprehensive
     (loss)/income, net
     of tax (Note 11):
      Unrealized gains/
       (losses) on
       marketable
       securities                 545            -         (109)           -
      Realized gains on
       marketable
       securities included
       in net income                -            -      (11,654)           -
      Gains and losses on
       derivatives
       designated as
       hedges in prior
       periods included
       in net income             (177)           -         (557)           -
    Change in cumulative
     translation
     adjustment               (39,711)         978      (98,334)     (22,671)
    -------------------------------------------------------------------------
    Other comprehensive
     (loss)/income            (39,343)         978     (110,654)     (22,671)

    -------------------------------------------------------------------------
    Comprehensive income
     (Note 2)             $    53,690  $   162,295  $   130,336  $   411,952
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                Three months ended         Nine months ended
    (CDN$ thousands)               September 30,             September 30,
     (Unaudited)                 2007         2006         2007         2006
    -------------------------------------------------------------------------

    Operating Activities
    Net income            $    93,033  $   161,317  $   240,990  $   434,623
    Non-cash items
     add/(deduct):

      Depletion,
       depreciation,
       amortization and
       accretion              116,001      129,400      352,001      362,134
      Change in fair
       value of
       derivative
       instruments
       (Note 3)                16,388      (16,754)      49,841      (42,513)
      Unit based
       compensation
       (Note 10)                2,192        1,765        6,410        4,291
      Foreign exchange
       on translation of
       senior notes
       (Note 8)               (15,586)          16      (39,276)      (2,732)
      Future income tax        (8,787)     (32,344)      38,419      (78,923)
      Amortization of
       senior notes
       premium                   (155)           -         (483)           -
      Reclassification
       adjustments from
       AOCI to net
       income                    (177)           -         (557)           -
    Gain on sale of
     marketable
     securities                     -            -      (14,055)           -
    Asset retirement
     obligations settled
     (Note 6)                  (3,547)      (1,636)     (10,664)      (7,220)
    -------------------------------------------------------------------------
                              199,362      241,764      622,626      669,660
    Decrease/(Increase)
     in non-cash working
     capital                   33,439       27,140       40,838      (13,071)
    -------------------------------------------------------------------------
    Cash flow from
     operating activities     232,801      268,904      663,464      656,589
    -------------------------------------------------------------------------
    Financing Activities
    Issue of trust units,
     net of issue costs
     (Note 10)                 15,087       13,713      246,311      281,957
    Cash distributions to
     unitholders             (163,110)    (154,700)    (483,388)    (459,293)
    (Decrease)/Increase
     in bank credit
     facilities                 8,145      (14,692)      72,495      (67,291)
    Decrease in non-cash
     financing working
     capital                      141          101        2,690        2,232
    -------------------------------------------------------------------------
    Cash flow from
     financing activities    (139,737)    (155,578)    (161,892)    (242,395)
    -------------------------------------------------------------------------
    Investing Activities
    Capital expenditures      (92,324)    (132,673)    (285,678)    (370,366)
    Property acquisitions      (1,755)      (4,296)    (214,399)     (46,553)
    Property dispositions          96          215       (1,056)       1,493
    Proceeds on sale of
     marketable securities          -            -       16,467            -
    Decrease/(Increase) in
     non-cash investing
     working capital            3,419       24,798      (11,078)      (5,711)
    -------------------------------------------------------------------------
    Cash flow from
     investing
     activities               (90,564)    (111,956)    (495,744)    (421,137)
    -------------------------------------------------------------------------
    Effect of exchange
     rate changes
     on cash                   (1,980)      (1,547)      (3,382)      (2,675)
    -------------------------------------------------------------------------
    Change in cash                520         (177)       2,446       (9,618)
    Cash, beginning of
     period                     2,050          652          124       10,093
    -------------------------------------------------------------------------
    Cash, end of period   $     2,570  $       475  $     2,570  $       475
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash
     Flow Information
    Cash income
     taxes paid           $     3,340  $         -  $    10,586  $     3,770
    Cash interest paid    $     6,052  $     4,563  $    26,782  $    19,324



    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 five new accounting standards that were issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 1530, Comprehensive Income, Handbook Section 3251, Equity, Handbook Section 3855, Financial Instruments - Recognition and Measurement, Handbook Section 3861, Financial Instruments - Disclosure and Presentation and Handbook Section 3865, Hedges. These standards were adopted 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). CICA Handbook Section 3251 establishes standards for the presentation of equity and changes in equity during the period. Financial Instruments - Recognition and Measurement CICA Handbook Section 3855 establishes the criteria for recognizing and measuring financial assets, financial liabilities and non- financial derivatives. Under this standard, all financial instruments are required to be measured at fair value on recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Financial assets and financial liabilities classified as held-for- trading are measured at fair value with changes in fair value recognized in net income. Financial assets classified as loans and receivables along with financial liabilities classified as other liabilities are measured at amortized cost using the effective interest rate method. Financial assets classified as available-for- sale are measured at fair value with changes in fair value recognized in OCI. Investments in equity instruments classified as available- for-sale that do not have a quoted price in an active market are measured at cost. Transaction costs or fees attributable to the acquisition, issue, or disposal of a financial asset or liability are expensed immediately to net income. Derivative instruments are recorded on the consolidated balance sheets at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net income with the exception of derivatives that are designated as effective cash flow hedges. Refer to the Hedges section for further detail. CICA Handbook Section 3861 establishes standards for the presentation and disclosure of financial instruments and non-financial derivatives. Hedges CICA Handbook Section 3865 specifies the criteria and method of accounting for each of the designated hedging strategies. When hedge accounting is discontinued for a cash flow hedge, the amounts previously recognized in AOCI are reclassified to net income over the remaining term of the hedged item. When hedge accounting is discontinued for a fair value hedge, the carrying value of the hedged item is no longer adjusted. Any difference between the carrying value and the face value or principal amount of the hedged item is amortized to net income over the remaining term of the original hedging relationship using the effective interest method. Impact upon Adoption of Sections 1530, 3251, 3855, 3861 and 3865 As a result of the adoption of these standards on January 1, 2007 the Fund elected to stop designating its interest rate and electricity swaps as cash flow hedges and recorded these items on the consolidated balance sheet at their fair values with the offset recorded to opening accumulated other comprehensive income. In addition, the Fund elected to stop designating its cross currency and interest rate swap ("CCIRS") as a fair value hedge and recorded the CCIRS on the consolidated balance sheet at fair value with the offset recorded to opening accumulated deficit. In conjunction, the underlying US$175,000,000 senior unsecured notes were recorded at fair value with the offset recorded to opening accumulated deficit. The Fund's investments in marketable securities have been classified as available-for-sale and 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 increased by $678,000 ($958,000 before future income taxes of $280,000) and $589,000 ($832,000 before future income taxes of $243,000) for the three and nine months ended September 30, 2007 respectively. Both the basic and diluted net income per trust unit calculations for the three months ended September 30, 2007 increased by $0.01 and were unchanged for the nine months ended September 30, 2007. 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 entity's capital and how it is managed. The standard requires qualitative information about an entity's objectives, policies and processes for managing capital and quantitative data about what the entity regards as capital. It requires disclosure of compliance with any capital requirements and consequences of any non-compliance. This standard is effective for January 1, 2008 and will result in additional disclosures around managing capital. 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 credit relating to crude oil instruments of $14,918,000 at September 30, 2007 consists of the fair value of the financial instruments, a loss position of $5,809,000, less the related deferred premiums of $9,109,000. The deferred financial asset relating to natural gas instruments of $20,301,000 at September 30, 2007 consists of the fair value of the financial instruments of $21,543,000 less the related deferred premiums of $1,242,000. Cross Currency Interest Interest Foreign Rate Rate Exchange Electricity ($ thousands) Swaps Swaps Swaps Swaps ------------------------------------------------------------------------- Deferred financial assets/(credits) as at December 31, 2006 $ - $ - $ - $ - Adoption of financial instruments standards(1) (673) (65,002) - 1,494 Change in fair value asset/(credits) 1,228(2) (31,071)(3) (1,253)(4) (516)(5) ------------------------------------------------------------------------- Deferred financial assets/(credits) as at September 30, 2007 $ 555 $ (96,073) $ (1,253) $ 978 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commodity Derivative Instruments ($ thousands) Oil Gas Total ------------------------------------------------------------------------- Deferred financial assets/(credits) as at December 31, 2006 $ 10,922 $ 12,690 $ 23,612 Adoption of financial instruments standards(1) - - (64,181) Change in fair value asset/(credits) (25,840)(6) 7,611(6) (49,841) ------------------------------------------------------------------------- Deferred financial assets/(credits) as at September 30, 2007 $ (14,918) $ 20,301 $(90,410)(7) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 $32,879) and interest expense (gain of $1,808). (4) Recorded in foreign exchange expense. (5) Recorded in operating expense. (6) Recorded in commodity derivative instruments (see below). (7) For financial statement presentation at September 30, 2007 this amount has been presented as a deferred financial asset of $21,834 and a deferred financial credit of $112,244. The following table summarizes the income statement effects of commodity derivative instruments: Commodity Derivative Three months ended Nine months ended Instruments September 30, September 30, ($ thousands) 2007 2006 2007 2006 ------------------------------------------------------------------------- Change in fair value, loss/(gain) $ 3,799 $ (26,992) $ 18,229 $ (89,491) Amortization of deferred financial assets - 10,238 - 46,978 Realized cash costs/ (gains), net (7,384) 843 (14,162) 40,334 ------------------------------------------------------------------------- Commodity derivative instruments $ (3,585) $ (15,911) $ 4,067 $ (2,179) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. PROPERTY, PLANT AND EQUIPMENT September 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Property, plant and equipment $ 6,282,141 $ 5,855,511 Accumulated depletion, depreciation and accretion (2,447,929) (2,129,414) ------------------------------------------------------------------------- Net property, plant and equipment $ 3,834,212 $ 3,726,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capitalized development G&A of $12,497,000 (2006 - $10,157,000) is included in property, plant and equipment ("PP&E") for the nine months ended September 30, 2007. Excluded from PP&E for the purpose of the depletion and depreciation calculation is $303,678,000 (2006 - $60,499,000) related to the Joslyn and Kirby development projects, 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 $20,276,000. The acquisition of Kirby has been accounted for as an asset acquisition pursuant to the guidance in the Emerging Issues Committee Abstract 124. 6. ASSET RETIREMENT OBLIGATIONS The following table reconciles the Fund's asset retirement obligations: Nine months ended Year ended September 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning of period $ 123,619 $ 110,606 Changes in estimates 5,362 12,757 Acquisition and development activity 1,939 5,574 Dispositions (759) (45) Asset retirement obligations settled (10,664) (11,514) Accretion expense 5,014 6,241 ------------------------------------------------------------------------- Asset retirement obligations, end of period $ 124,511 $ 123,619 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. LONG-TERM DEBT September 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Bank credit facilities (a) $ 421,015 $ 348,520 Senior notes (b) US$175 million (issued June 19, 2002) 177,584 268,328 US$54 million (issued October 1, 2003) 53,800 62,926 ------------------------------------------------------------------------- Total long-term debt $ 652,399 $ 679,774 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (a) Unsecured Bank Credit Facility Enerplus currently has a $1.0 billion unsecured covenant based three year term facility ($850,000,000 at September 30, 2007). The facility is extendible each year with a bullet payment required at the end of the three year term. Subsequent to September 30, 2007 the bank credit facility was extended by one year to November 2010. In addition, the facility size was increased and there were no changes to the floating interest rates under the facility. 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 nine months ended September 30, 2007 was 5.0% (2006 - 4.7%). (b) Senior Unsecured Notes On October 1, 2003 when the Cdn/US exchange rate was 1.35 Enerplus issued US$54,000,000 senior unsecured notes that mature October 1, 2015. The notes have a coupon rate of 5.46% priced at par with interest paid semi- annually on April 1 and October 1 of each year. Principal payments are required in five equal installments beginning October 1, 2011 and ending October 1, 2015. The notes are translated into Canadian dollars using the period end foreign exchange rate. During September 2007 Enerplus entered into foreign exchange swaps that effectively fix the five principal payments on the US$54,000,000 senior unsecured notes at a CAD/US exchange rate of 1.02. On 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 September 30, 2007 the amortized cost of the US$175,000,000 senior notes was US$178,243,000. 8. FOREIGN EXCHANGE Three months ended Nine months ended September 30, September 30, ------------------------------------------------------------------------- ($ thousands) 2007 2006 2007 2006 ------------------------------------------------------------------------- Unrealized foreign exchange (gain)/loss on translation of U.S. dollar denominated senior notes $ (15,586) $ 16 $ (39,276) $ (2,732) Unrealized foreign exchange loss on cross currency interest rate swap 14,105 - 32,879 - Unrealized foreign exchange loss on foreign exchange swaps 1,253 - 1,253 - Realized foreign exchange (gain)/loss (415) (655) 1,027 (161) ------------------------------------------------------------------------- Foreign exchange gain $ (643) $ (639) $ (4,117) $ (2,893) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed to foreign currency fluctuations and are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in the determination of net income for the period. 9. INTEREST EXPENSE Three months ended Nine months ended September 30, September 30, ($ thousands) 2007 2006 2007 2006 ------------------------------------------------------------------------- Interest on long-term debt $ 10,405 $ 8,586 $ 29,842 $ 23,592 Unrealized gain on cross currency interest rate swap (4,718) - (1,808) - Unrealized loss/(gain) on interest rate swaps 871 - (1,228) - Amortization of the premium on senior unsecured notes (120) - (406) - ------------------------------------------------------------------------- Interest Expense $ 6,438 $ 8,586 $ 26,400 $ 23,592 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 10. FUND CAPITAL (a) Unitholders' Capital Trust Units Authorized: Unlimited number of trust units Nine months ended Year ended Issued: September 30, 2007 December 31, 2006 (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 157 5,379 640 22,974 Trust unit rights incentive plan (non-cash) - exercised - 1,816 - 3,065 DRIP(*), net of redemptions 889 41,374 602 32,928 Issued for acquisition of property interests (non-cash) 1,105 54,750 - - ------------------------------------------------------------------------- 129,552 4,009,698 123,151 3,706,821 Contributed Surplus (Trust Unit Rights Plan) - 10,899 - 6,305 ------------------------------------------------------------------------- Balance, end of period 129,552 $4,020,597 123,151 $3,713,126 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Distribution Reinvestment and Unit Purchase Plan Nine months ended Year ended Contributed Surplus September 30, December 31, ($ thousands) 2007 2006 ------------------------------------------------------------------------- Balance, beginning of period $ 6,305 $ 3,047 Trust unit rights incentive plan (non-cash) - exercised (1,816) (3,065) Trust unit rights incentive plan (non-cash) - expensed 6,410 6,323 ------------------------------------------------------------------------- Balance, end of period $ 10,899 $ 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 September 30, 2007, a total of 3,494,000 rights issued pursuant to the Trust Unit Rights Incentive Plan ("Rights Plan") with an average exercise price of $47.89 were outstanding. This represents 2.7% of the total trust units outstanding of which 1,151,000 rights with an average exercise price of $43.69 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, second and third 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) and $0.52 per trust unit (effective January 2008), respectively. Activity for the rights issued pursuant to the Rights Plan is as follows: Nine months ended Year ended September 30, 2007 December 31, 2006 ---------------------------------------------- Weighted Weighted Number Average Number Average of Rights Exercise of 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 802 48.89 1,473 54.49 Exercised (157) 34.35 (640) 35.94 Cancelled (230) 50.90 (375) 46.35 ------------------------------------------------------------------------- End of period 3,494 $ 47.89 3,079 $ 48.53 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Rights exercisable at the end of the period 1,151 $ 43.69 809 $ 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 nine months ended September 30, 2007 were $2,192,000 ($0.02 per unit) and $6,410,000 ($0.05 per unit) respectively. The non-cash compensation costs for the three and nine months ended September 30, 2006 were $1,765,000 ($0.01 per unit) and $4,291,000 ($0.04 per unit) respectively. (c) Basic and Diluted per Trust Unit Calculations Net income per trust unit has been determined based on the following: Nine months ended September 30, (thousands) 2007 2006 ------------------------------------------------------------------------- Weighted average units 127,031 121,120 Dilutive impact of rights 58 391 ------------------------------------------------------------------------- Diluted trust units 127,089 121,511 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (d) Cash Distributions to Unitholders Cash distributions to unitholders for the three months ended September 30, 2007 were $163,110,000 (2006 - $154,700,000). Cash distributions to unitholders for the nine months ended September 30, 2007 were $483,388,000 (2006 - $459,293,000). Cash distributions are determined by the Board of Directors in accordance with the Trust indenture and are paid monthly. 11. 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 which are reported at cost. At September 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 September 30, 2007 the Fund reported investments in marketable securities of publicly traded marketable securities at a fair value of $13,077,000. For the three months ended September 30, 2007, the change in fair value of these investments represented a gain $769,000 ($544,000 net of tax). For the nine months ended September 30, 2007 the change in fair value of these investments represented a loss of $154,000 ($109,000 net of tax). Marketable securities without a quoted market price in an active market are reported at cost. As at September 30, 2007 the Fund reported investments in marketable securities of private companies at 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. At September 30, 2007 total marketable securities of $58,402,000 are presented as other assets on the Consolidated Balance Sheet. Any 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 cost. At September 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 cost. At September 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 September 30, 2007 the Canadian dollar amortized cost of the senior notes was approximately $53,800,000. 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$178,243,000 and are translated to Canadian dollars at the period end exchange rate. At September 30, 2007 the Canadian dollar amortized cost of the senior notes was approximately $177,584,000. 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 September 30, 2007 the fair value of the interest rate swaps represented an asset of $555,000. For the nine months ended September 30, 2007, the change in fair value of these contracts represented an unrealized gain of $1,228,000. Cross Currency Interest Rate Swap (CCIRS) Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a CCIRS with a syndicate of financial institutions. Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal payments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian bankers' acceptances, plus 1.18%. The CCIRS is classified as held-for-trading and is reported at fair value. At September 30, 2007 the fair value of the CCIRS represented a liability of $96,073,000. For the nine months ended September 30, 2007, the change in fair value of the CCIRS represented an unrealized loss of $31,071,000. Foreign Exchange Swaps In September 2007 the Fund entered into foreign exchange swaps on US $54,000,000 of notional debt at an average CAD/US foreign exchange rate of 1.02. These foreign exchange swaps mature between October 2011 and October 2015 in conjunction with the principal repayments on the US $54,000,000 senior notes. The foreign exchange swaps are classified as held-for-trading and are reported at fair value. At September 30, 2007 the fair value of the interest rate swaps represented a liability of $1,253,000. For the nine months ended September 30, 2007, the change in fair value of these contracts represented an unrealized loss of $1,253,000. Electricity Instruments The Fund has entered into electricity swaps that fix the price of electricity. These contracts are classified as held-for-trading and are reported at fair value. At September 30, 2007 the fair value of these contracts represented an asset of $978,000. For the nine months ended September 30, 2007, the change in fair value of these contracts represented an unrealized loss of $516,000. Unrealized gains or losses resulting from changes in fair value along with realized gains or losses on settlement of the electricity contracts are recognized as operating costs. The following table summarizes the Fund's electricity management positions at October 29, 2007. Volumes Price Term MWh CDN$/MWh ------------------------------------------------------------------------- October 1, 2007 - December 31, 2007 5.0 $ 61.50 October 1, 2007 - December 31, 2007 4.0 $ 62.90 January 1, 2008 - September 30, 2008 4.0 $ 63.00 ------------------------------------------------------------------------- The Fund did not enter into any new electricity contracts in the third quarter of 2007. 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 September 30, 2007 the fair value of these contracts represented a liability of $14,918,000. For the nine months ended September 30, 2007, the change in fair value of these contracts represented an unrealized loss of $25,840,000. The net premium cost of the crude oil instruments entered into as of September 30, 2007 is $9,109,000. The following table summarizes the Fund's crude oil risk management positions at October 29, 2007: WTI US$/bbl ---------------------------------------- Fixed Daily Price Volumes Sold Purchased Sold and bbls/day Call Put Put Swaps ------------------------------------------------------------------------- Term October 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 Swap(1) 600 - - - $76.00 November 1, 2007 - December 31, 2007 Costless Collar(1) 1,500 $84.10 $76.00 - - January 1, 2008 - June 30, 2008 Put(1) 1,500 - $74.00 - - January 1, 2008 - December 31, 2008 Collar 750 $77.00 $67.00 - - 3-Way option 1,000 $84.00 $66.00 $50.00 - 3-Way option 1,000 $84.00 $66.00 $52.00 - 3-Way option 1,000 $86.00 $68.00 $52.00 - 3-Way option(1) 1,000 $87.50 $70.00 $52.00 - 3-Way option(1) 1,500 $90.00 $70.00 $60.00 - Put Spread(2) 1,500 - $76.50 $58.00 - Swap(1) 750 - - - $72.94 Swap(1) 750 - - - $74.00 Swap(1) 750 - - - $73.80 Swap(1) 750 - - - $73.35 January 1, 2009 - December 31, 2009 3-Way option(2) 1,000 $85.00 $70.00 $57.50 - ------------------------------------------------------------------------- (1) Financial contracts entered into during the third quarter of 2007. (2) Financial contracts entered into subsequent to September 30, 2007. Natural Gas Instruments Enerplus has certain physical and financial contracts outstanding as at October 29, 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 $0.38/Mcf on 21.2MMcf/day for the month of October 2007. These contracts are classified as held-for-trading and are reported at fair value. At September 30, 2007 the fair value of these contracts represented an asset of $20,301,000. For the nine months ended September 30, 2007, the change in fair value of these contracts represented an unrealized gain of $7,611,000. The net premium cost of the financial natural gas instruments entered into as of September 30, 2007 is $1,242,000. The following table summarizes the Fund's natural gas risk management positions at October 29, 2007: AECO CDN$/Mcf ---------------------------------------- Fixed Daily Price Volumes Sold Purchased Sold and MMcf/day Call Put Put Swaps ------------------------------------------------------------------------- Term October 1, 2007 - October 31, 2007 Collar 6.6 $10.02 $7.50 - - Collar 6.6 $ 9.00 $7.50 - - Collar 9.5 $ 9.11 $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 2.4 $10.15 $8.00 - - 3-Way option 4.7 $10.50 $8.20 $5.70 - 3-Way option 9.5 $11.61 $8.97 $6.33 - 3-Way option 4.7 $11.08 $8.55 $6.01 - 3-Way option(1) 4.7 $ 9.50 $7.49 $5.70 - 3-Way option(1) 9.5 $ 9.50 $7.39 $5.70 - Swap 4.7 - - - $8.70 Swap 2.4 - - - $9.01 April 1, 2008 - October 31, 2008 3-Way option(2) 11.8 $ 7.91 $6.75 $5.49 - 3-Way option 5.7 $ 9.50 $7.54 $5.28 - Collar(1) 6.6 $ 8.44 $7.17 - - Swap 4.7 - - - $8.18 November 1, 2008 - March 31, 2009 3-Way option(1) 5.7 $10.71 $7.91 $5.80 - 2007 - 2010 Physical (escalated pricing) 2.0 - - - $2.52 ------------------------------------------------------------------------- (1) Financial contracts entered into during the third quarter of 2007. (2) Financial contracts entered into subsequent to September 30, 2007. Enerplus has captured the gain on former fixed price swaps by purchasing 19 MMcf/day at a fixed price of $4.91/Mcf from October 1, 2007 to October 31, 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

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


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