<Page>

                                                                     Exhibit 4.7

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


The following discussion and analysis of the financial results of Enerplus
Resources Fund ("Enerplus" or the "Fund") should be read in conjunction with:

o    the MD&A and Audited  Consolidated  Financial Statements as at and for the
     years ended December 31, 2001 and 2000; and
o    the Interim Unaudited Consolidated Financial Statements as at and for the
     three and nine months ended September 30, 2002 and 2001.

All amounts are stated in Canadian dollars unless otherwise specified. Where
applicable, natural gas has been converted to barrels of oil equivalent ("BOE")
based on 6 Mcf:1 BOE. In accordance with Canadian practice, production volumes,
reserve volumes and revenues are reported on a gross basis, (before crown and
freehold royalties), unless otherwise indicated.


THIRD QUARTER 2002 HIGHLIGHTS

o    The Fund paid $0.88 per trust unit ($64.5 million) in cash distributions to
     Unitholders with respect to the quarter and retained $0.05 per trust unit
     ($3.9 million) to reduce debt incurred on acquisition and development
     spending.

o    On August 8, 2002, Enerplus acquired a 16% working interest in Oil Sands
     Lease #24 (also known as the Joslyn Creek Lease) for $16.4 million and the
     assumption of $4.1 million in contingent project debt.

o    On September 12, 2002, the Fund successfully closed an equity offering of
     4,750,000 trust units at a price of $26.85 per trust unit for gross
     proceeds of $127.5 million.

o    The Fund experienced lower prices for its natural gas and NGLs in the third
     quarter of 2002 when compared to the third quarter of 2001. Both natural
     gas and NGL prices declined 2% during this time period. These price
     declines were offset by a 7% increase in the price of crude oil over the
     same period.

o    Operating costs of $6.21/BOE for the three months ended September 30, 2002
     were slightly lower than the same period in 2001 of $6.25/BOE. During the
     nine months ended 2002, operating costs continued to be in line with prior
     periods with operating costs decreasing slightly to $5.71/BOE from
     $5.77/BOE during the comparable period in 2001.

o    Enerplus continued with its active development program, investing $44.8
     million in development drilling and facility enhancements for the three
     months ended September 30, 2002. During the quarter, Enerplus drilled 135
     gross wells (117.1 net wells) with a 99% success rate.

o    Subsequent to the end of the third quarter, Enerplus completed the
     acquisition of Celsius Energy Resources Ltd. for $165.9 million inclusive
     of working capital adjustments. The Fund acquired daily production volumes
     of 5,750 BOE/day and 18 MMBOE of established reserves.


IMPORTANT INFORMATION REGARDING COMPARATIVE FINANCIAL STATEMENTS

On June 21, 2001, the respective Unitholders of EnerMark Income Fund
("EnerMark") and Enerplus Resources Fund overwhelmingly approved a merger
combining the two funds (the "Merger"). As the former Unitholders of EnerMark
held approximately 69% of the outstanding trust units of the combined fund at
the date of acquisition, the Merger was accounted for using the reverse takeover
form of the purchase method of accounting for business combinations. For
accounting purposes, EnerMark acquired Enerplus effective June 21, 2001 and
continues as Enerplus Resources Fund which has a 16-year history, market
recognition and a listing on the New York Stock Exchange.

With the reverse takeover form of the purchase method of accounting, the
unaudited consolidated financial statements presented herein include the
accounts of EnerMark and Enerplus as at and for the


<Page>

three and nine months ended September 30, 2002. The historical comparative
financial information for the year 2001 presented in the interim unaudited
consolidated financial statements includes the results of EnerMark for the
entire period, and only the results of Enerplus for the period from the date of
the Merger to September 30, 2001.


RESULTS OF OPERATIONS

PRODUCTION

Daily production averaged 60,730 BOE/day during the three months ended September
30, 2002, representing a 1% increase over production volumes of 60,331 BOE/day
for the same period in 2001. Production remained relatively consistent over the
periods as natural reservoir declines were more than offset by production gains
from acquisition and development activity. This was particularly evident for
crude oil as the volumes increased 5% or 1,092 bbls/day for the three months
ended September 30, 2002 compared to 2001. The majority of this increase can be
attributed to the property acquisition in the Medicine Hat Glauconite "C" area
during the first quarter of 2002. Natural gas production during the third
quarter of 2002 was lower compared to the three months ended June 30, 2002 due
to plant turnarounds and maintenance.

Production for the nine months ended September 30, 2002 increased 19% to 61,493
BOE/day compared to the corresponding period in 2001. This increase is
attributable to the Merger that occurred on June 21, 2001. The nine month
comparison of 2001 production reflects the volumes of the predecessor Enerplus
Resources Fund only from the date of the Merger.

Enerplus expects production levels to increase in the fourth quarter as a result
of the Celsius acquisition combined with incremental production gains as wells
drilled in the third quarter are brought on stream. Production from the Celsius
acquisition is not recorded in the third quarter as the transaction closed
October 21, 2002 and production from the newly acquired Oil Sands Lease #24 is
not expected until 2004.

Enerplus' average production portfolio for the three months ended September 30,
2002 was weighted 54% natural gas, 39% crude oil, and 7% natural gas liquids on
a per BOE basis. Average production volumes are outlined as follows:

<Table>
<Caption>
                                      THREE MONTHS                                NINE MONTHS
                                   ENDED SEPTEMBER 30,          %             ENDED SEPTEMBER 30,          %
                               ----------------------------                ---------------------------
                                  2002             2001       CHANGE          2002            2001       CHANGE
                               ------------     ----------- -----------    -----------     ----------- -----------
<S>                            <C>              <C>         <C>            <C>             <C>         <C>
DAILY SALES VOLUMES
  Natural gas (Mcf/day)            198,452          199,823      (1%)         204,463         167,304       22%
  Crude oil (bbls/day)              23,560           22,468       5%           23,117          19,760       17%
  NGLs (bbls/day)                    4,095            4,559     (10%)           4,299           3,879       11%
                               ------------     ----------- -----------    -----------     ----------- -----------
  Total daily sales
     (BOE/day)                      60,730           60,331       1%           61,493          51,523       19%
                               ============     =========== ===========    ===========     =========== ===========
</Table>

PRICING AND PRICE RISK MANAGEMENT

Although the AECO monthly index price decreased 17% from $3.92/Mcf in 2001 to
$3.25/Mcf in 2002, the Fund experienced only a 2% decline in the average price
(before hedging) received on natural gas from $3.43/Mcf for the three months
ended September 30, 2001 to $3.37/Mcf for the same period in 2002. Enerplus was
able to moderate the decline in the AECO index through the benefit of a number
of fixed price natural gas delivery contracts. For the nine months ended
September 30, 2002, Enerplus' natural gas prices (before hedging) decreased 39%
from the comparable period 2001. This decline is consistent with the sharp
reduction in the AECO and NYMEX price indices from the peak experienced during
the first half of 2001.

The average price that Enerplus received for its crude oil (before hedging)
increased 7% from CDN$35.11/bbl for the third quarter of 2001 to CDN$37.41/bbl
in the same quarter in 2002, which corresponds with the increase in the price of
benchmark West Texas Intermediate (WTI) crude oil after adjusting for the change
in the US$ exchange rate. For the nine months ended September 30, 2002 the


<Page>

average price received for crude oil (before hedging) decreased 1% from the
comparable period in 2001, lower than the 9% decrease in price of the WTI crude
oil. This difference is mainly due to the different product mix recognized in
2002 as a result of the Merger.

The realized prices for natural gas liquids ("NGLs") decreased 2% from the third
quarter of 2001 to average $25.81/bbl for the third quarter of 2002. For the
nine months ended September 30, 2002, NGL prices decreased 34% from the
comparable period in 2001. In both the three and nine month comparisons, the
realized prices for NGLs were influenced by the corresponding prices for natural
gas.

<Table>
<Caption>
                                             THREE MONTHS                                NINE MONTHS
                                          ENDED SEPTEMBER 30,         %              ENDED SEPTEMBER 30,          %
                                       --------------------------                 ---------------------------
                                          2002           2001       CHANGE           2002           2001        CHANGE
                                       -----------    ----------- -----------     -----------    ------------ -----------
<S>                                    <C>            <C>         <C>             <C>            <C>          <C>
AVERAGE SELLING PRICE
(before hedging)
  Natural gas (per Mcf)                  $3.37          $3.43         (2%)           $3.44          $5.68     (39%)
  Crude oil (per bbl)                   $37.41         $35.11          7%           $33.69         $33.93       (1%)
  NGLs (per bbl)                        $25.81         $26.29         (2%)          $23.06         $34.79     (34%)
  Total daily sales (per BOE)           $27.24         $26.38          3%           $25.69         $34.08     (25%)
</Table>

<Table>
<Caption>

                                             THREE MONTHS                                NINE MONTHS
                                          ENDED SEPTEMBER 30,         %              ENDED SEPTEMBER 30,          %
                                       --------------------------                 ---------------------------
BENCHMARK PRICING                         2002           2001       CHANGE           2002           2001        CHANGE
                                       -----------    ----------- -----------     -----------    ------------ -----------
<S>                                    <C>            <C>         <C>             <C>            <C>          <C>
AECO (30 day) natural gas
  (per Mcf)                            $3.25          $3.92       (17%)           $3.67          $7.30         (50%)
NYMEX natural gas
  (US$ per Mcf)                        $3.26          $2.98          9%           $3.01          $5.01         (40%)
WTI crude oil (US$ per bbl)            $28.27         $26.76         6%           $25.39         $27.82         (9%)
Currency $1 CDN in US $                $0.6398        $0.6472       (1%)          $0.6369        $0.6502        (2%)
</Table>

Enerplus has continued to implement hedging transactions in accordance with its
commodity price risk management program during the third quarter. The program is
intended to provide a measure of stability to the Fund's cash distributions as
well as ensure Enerplus realizes positive economic returns from its capital
development and acquisition activities. Enerplus' commodity risk management
program is described in detail in Note 5 to the interim consolidated financial
statements. Enerplus has the following physical and financial contracts in
place:
<Table>
<Caption>
                                     CONTRACTED              % OF               CONTRACTED             % OF
                                    GAS VOLUMES         ESTIMATED GROSS        OIL VOLUMES       ESTIMATED GROSS
PHYSICAL & FINANCIAL                 (MMCF/DAY)         GAS PRODUCTION*          BBLS/DAY        OIL PRODUCTION*
                                 ------------------- ---------------------- ------------------- -------------------
<S>                               <C>                     <C>                 <C>                  <C>
Remainder 2002                        66.0                    29%                 11,175               45%
          2003                        75.0                    33%                 11,000               44%
          2004                        44.0                    19%                  6,500               26%
</Table>

* Production volumes measured with reference to year-to-date production adjusted
for the Celsius acquisition.

For the three months ended September 30, 2002, Enerplus realized a hedging gain
of $0.8 million on natural gas and a hedging loss of $1.7 million on crude oil
as a result of its price risk management program. This realized loss is mainly
due to an improvement in the markets for crude oil while the realized gain was
due to a decrease in natural gas prices during the quarter. For the nine months
ended September 30, 2002, Enerplus has realized a hedging loss on both natural
gas and crude oil of $0.5 million and $2.4 million respectively. For the
comparable period in 2001, Enerplus realized a $3.1 million hedging loss on
crude oil and a $16.2 million hedging gain on natural gas. The mark-to-market
value of Enerplus' forward commodity price contracts at September 30, 2002
represented an unrealized loss of $18.0 million for natural gas and an
unrealized loss of $9.0 million for crude oil. In other words, if Enerplus was
to settle its forward commodity price contracts at September 30, 2002 with
reference to the forward market at that time, it would have to make a payment of
approximately $27.0 million. The mark-to-market loss has widened from the second
quarter because the forward prices for crude oil and natural gas had
strengthened by September 30, 2002.


<Page>

OIL AND GAS SALES

Crude oil and natural gas revenues, including net hedging costs, were $151.3
million for the three months ended September 30, 2002, which was 8% lower than
the $163.8 million reported for the same period in 2001. The decreased revenue
was primarily due to a gain of $18.9 million realized in 2001 on natural gas
hedging contracts. For the nine months ended September 30, 2002, crude oil and
natural gas revenues, including net hedging costs, were $428.4 million compared
to $492.4 million for the comparable period in 2001.

ANALYSIS OF SALES REVENUES ($ MILLIONS)
<Table>
<Caption>
                                                                                      NATURAL
                                               CRUDE OIL             NGLS               GAS                TOTAL
                                             --------------     ---------------    ---------------     --------------
<S>                                              <C>                <C>                <C>                <C>
2001 - 3rd Quarter Revenues                      $71.0              $11.0              $81.8              $163.8

Price variance                                     5.0               (0.2)              (1.1)                3.7
Volume variance                                    3.6               (1.1)              (0.4)                2.1
Hedging cost variance                             (0.2)               -                (18.1)              (18.3)
                                             --------------     ---------------    ---------------     --------------

2002 - 3rd Quarter Revenues                      $79.4               $9.7              $62.2              $151.3
                                             ==============     ===============    ===============     ==============
</Table>

ROYALTIES

Royalties decreased from $32.9 million or 20% of oil and gas sales for the three
months ended September 30, 2001 to $29.0 million or 19% for the three months
ended September 30, 2002. For the nine months ended September 30, 2002 royalties
decreased from $115.6 million or 23% of oil and gas sales in 2001 to $88.5
million or 21% of oil and gas sales. In the three and nine month comparisons,
the decline in royalties as a percentage of oil and gas sales is attributable to
a lower reference natural gas price used to calculate crown royalties during
2002.


OPERATING EXPENSES

Operating expenses totaled $34.7 million or $6.21/BOE for the three months ended
September 30, 2002 compared to $34.7 million or $6.25/BOE for the third quarter
of 2001. Third quarter operating expenses tend to be higher as a result of
increased maintenance costs, plant turnarounds and property tax charges which
are incurred during this period. Operating expenses for the nine months ended
September 30, 2002 increased 18% to $95.9 million from the comparable period in
2001 due to the Merger, however, after reflecting the higher production levels,
operating expenses per BOE have been reduced to $5.71/BOE from $5.77/BOE during
this time period. Enerplus expects operating costs to continue in this range to
the end of 2002.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative ("G&A") expenses were $3.4 million or $0.60/BOE for
the three months ended September 30, 2002 compared to $1.6 million or $0.29/BOE
for the same period in 2001. Net G&A costs for the third quarter of 2001 were
lower than expected due to one-time adjustments for cost recoveries. G&A
expenses for the nine months ended September 30, 2002 of $10.1 million are in
line with annual expectations of $0.60/BOE.

In accordance with the full cost method of accounting, Enerplus capitalized $2.0
million or 25% of gross G&A costs for the three months ended September 30, 2002
compared to $1.8 million or 28% for the same period in 2001. For the nine month
period ended September 30, 2002, Enerplus capitalized $6.1 million of gross G&A
costs compared to $4.6 million for the comparable period in 2001. The majority
of these capitalized costs represent compensation costs for staff involved in
development and acquisition activities.

<Page>

<Table>
<Caption>

MANAGEMENT FEES
                                                                THREE MONTHS                   NINE MONTHS
                                                             ENDED SEPTEMBER 30,           ENDED SEPTEMBER 30,
                                                          --------------------------    ---------------------------
($ millions)                                                 2002           2001           2002            2001
                                                          -----------    -----------    ------------    -----------
<S>                                                         <C>            <C>            <C>              <C>
Base management fees                                        $2.3           $2.5           $ 6.3            $7.0
Performance fees                                             4.9            -               7.3             -
                                                          -----------    -----------    ------------    -----------
Total management fees                                       $7.2           $2.5           $13.6            $7.0
                                                          ===========    ===========    ============    ===========
</Table>

Base management fees, which are calculated based on 2.75% of net operating
income, decreased to $2.3 million during the three months ended September 30,
2002 from $2.5 million for the same period in 2001. The decrease is a result of
lower net operating income experienced during the period. For the nine months
ended September 30, 2002, base management fees decreased to $6.3 million from
$7.0 million for the same period in 2001. The decrease in the nine month
comparison is a result of lower net operating income experienced during the
period, offset slightly by the increase in the rate used to calculate the base
management fees from 2.20% to 2.75%, as a result of the restructured management
fee associated with the Merger.

The performance fee can range between 0% and 4% of the Fund's annual operating
income based on the total return of the Fund and the relative performance
compared to other senior oil and gas trusts. Although the performance fee is
determined on December 31, 2002, management has accrued a performance fee based
on the fact that, had the calculation been performed at September 30, 2002, the
performance fee for 2002 would be 3.0% of net operating income. The $7.3 million
is an estimate that may increase or decrease throughout the remainder of the
year until the performance fee is calculated and finalized at December 31.

INTEREST EXPENSE

Interest expense for the three months ended September 30, 2002 was $5.2 million,
an increase from $5.1 million recognized during the comparable period of 2001.
Although the Fund's average long-term debt has decreased compared to the same
period in 2001, the average floating interest rate paid by the Fund has
increased.

For the nine months ended September 30, 2002, interest expense was $12.7
million, a decrease from $13.5 million recognized during the comparable period
of 2001. The decrease is attributable to lower outstanding average long-term
debt along with a reduction in interest rates over the period.

As at September 30, 2002, Enerplus had floating interest rates with respect to
$94.2 million in bank debt and $268.3 million in senior unsecured debentures.
However, with respect to this long-term debt, it had interest rate swaps on
$75.0 million that fixed the rate of interest before stamping fees between 3.89%
and 4.70% for three-year terms.

DEPLETION, DEPRECIATION AND AMORTIZATION

Depletion, depreciation and amortization decreased to $52.7 million or $9.42/BOE
for the three months ended September 30, 2002 from $55.4 million or $9.98/BOE
for the same period in 2001. Included in the 2001 balance are amortization costs
related to deferred hedging assets amounting to $3.9 million that were fully
amortized by the end of 2001. For the nine months ended September 30, 2002,
depletion, depreciation and amortization was $158.9 million or $9.47/BOE
compared to $135.9 million or $9.66/BOE for the same period in 2001. These
differences are a result of the Merger. Higher production volumes during 2002
have increased the amount of depletion, depreciation and amortization expense,
while the change in the overall depletable reserves has decreased the rate of
depletion, depreciation and amortization per BOE. When applying a ceiling test
to our capital assets as at September 30, 2002, no write down was required.


<Page>


TAXES

For the three months ended September 30, 2002, a future income tax recovery of
$11.1 million was recorded in income. Under Canadian generally accepted
accounting principles, the Fund does not recognize any future income taxes as
taxable income is distributed to Unitholders in the form of taxable
distributions. However, the Fund's operating companies are required to account
for future income taxes. Future income taxes for the operating companies are
dependent upon the method by which funds are transferred to the Fund from the
operating companies. The future income tax recovery occurs when tax deductible
distributions, which can take the form of interest or royalties, are transferred
from the operating companies to the Fund's Unitholders. During the quarter,
increased tax deductible distributions were made from the operating companies to
the Fund.


NETBACKS
<Table>
<Caption>

Netbacks per BOE of production (6:1)                          THREE MONTHS                        NINE MONTHS
                                                          ENDED SEPTEMBER 30,                 ENDED SEPTEMBER 30,
                                                     -------------------------------     ------------------------------
For the period ended September 30,                       2002              2001              2002             2001
-------------------------------------------------    -------------     -------------     -------------    -------------

<S>                                                      <C>               <C>               <C>              <C>
Oil and gas sales                                        $27.08            $29.51            $25.52           $35.01
Royalties                                                 (5.19)            (5.94)            (5.27)           (8.22)
Operating costs                                           (6.21)            (6.25)            (5.71)           (5.77)
                                                     -------------     -------------     -------------    -------------
Operating netback per BOE                                $15.68            $17.32            $14.54           $21.02
General and administrative costs                          (0.60)            (0.29)            (0.60)           (0.45)
Management fees                                           (1.30)            (0.45)            (0.80)           (0.49)
Net interest                                              (0.92)            (0.90)            (0.74)           (0.91)
Capital taxes                                             (0.22)            (0.25)            (0.24)           (0.26)
                                                     -------------     -------------     -------------    -------------
Total cash netback per BOE                               $12.64            $15.43            $12.16           $18.91
                                                     -------------     -------------     -------------    -------------
</Table>


NET INCOME AND FUNDS FLOW FROM OPERATIONS
<Table>
<Caption>
                                                             THREE MONTHS                        NINE MONTHS
                                                          ENDED SEPTEMBER 30,                ENDED SEPTEMBER 30,
                                                     ------------------------------     -------------------------------
($ millions) except per trust unit amounts              2002              2001             2002              2001
                                                     -------------     -------------    -------------     -------------
<S>                                                    <C>               <C>              <C>               <C>
Net income                                             $29.1             $25.1            $64.5             $143.3
Net income per trust unit                              $0.41             $0.39            $0.92             $2.82
Funds flow from operations                             $69.6             $85.0            $200.9            $264.6
Funds flow from operations per trust unit              $0.98             $1.31            $2.87             $5.22
</Table>

The increase in net income for the three months ended September 30, 2002, is a
result of higher average crude oil prices recognized during the third quarter of
2002 compared to the same period in 2001, offset slightly by the additional
performance fee that has been accrued during the period. The decrease in funds
flow from operations for the three months ended September 30, 2002 is due to an
$18.9 million gain recognized from natural gas hedging contracts during the same
period in 2001.

The change in net income and funds flow from operations for the nine months
ended September 30, 2002, is due to a combination of a $16.2 million gain
recognized from natural gas hedging contracts during 2001, a sharp decline in
natural gas prices realized during 2002 from those experienced during the first
and second quarters of 2001 and the fact that the 2001 year-to-date results are
those strictly of EnerMark to the date of the Merger.

Management monitors the Fund's distribution payout policy with respect to
forecast cash flows, debt levels, and spending plans. Management is prepared to
adjust the payout levels in an effort to balance the investor's desire for
distributions with the Fund's requirement to maintain a prudent capital
structure.

The following table reconciles Enerplus' "Funds Flow from Operations" as per the
Statement of Cash Flows with the cash available for distribution to Unitholders.


<Page>

<Table>
<Caption>

Reconciliation of Cash Available for                        THREE MONTHS                        NINE MONTHS
Distribution for the Period                              ENDED SEPTEMBER 30,                ENDED SEPTEMBER 30,
-----------------------------------------------     ------------------------------     ------------------------------
($ millions except per unit amounts)                    2002             2001              2002             2001
                                                    -------------    -------------     -------------    -------------
<S>                                                     <C>              <C>              <C>              <C>
Funds flow from operations                              $69.6            $84.9            $200.9           $264.6
Cash withheld for debt reduction                         (3.9)            (5.6)            (33.9)           (32.2)
Enerplus cash flows                                       -                -                 -               16.9
Accruals *                                               (1.2)             2.3               3.5              4.6
                                                     -------------     -------------     -------------    -------------
Cash available for distribution                         $64.5            $81.6            $170.5           $253.9
                                                     =============     =============     =============    =============
Cash available for distribution
  per trust unit                                        $0.88            $1.25             $2.40            $4.77
</Table>

*  According to the Royalty Agreement with Enerplus Resources Corporation, the
   royalty paid to the Fund must be on a cash basis. As a consequence, the
   change in accrued net revenues for the period is added back to (deducted
   from) funds flow from operations for purposes of this reconciliation.

With respect to the third quarter of 2002, Enerplus distributed $64.5 million,
or $0.88 per trust unit in cash distributions to Unitholders (94% of funds flow
from operations) and withheld $3.9 million or $0.05 per trust unit for debt
reduction (6% of funds flow from operations). For the nine month period,
Enerplus has distributed $170.5 million, or $2.40 per trust unit (83% of funds
flow from operations) and withheld $33.9 million or $0.48 per trust unit for
debt reduction (17% of funds flow from operations).

Cash available for distribution per trust unit of $0.88 for the three months
ended September 30, 2002 represents what an Enerplus Unitholder will have
received from the production relating to the third quarter of 2002 (paid to
Unitholders on September 20, October 20, and November 20, 2002). Cash available
for distribution was $1.25 per trust unit for the same period in 2001.

CAPITAL EXPENDITURES

During the three months ended September 30, 2002, Enerplus spent $46.1 million
(2001 - $41.9 million) on capital expenditures prior to acquisitions and
divestitures with a focus on development drilling in the Joarcam area. During
the nine months ended September 30, 2002, Enerplus spent $101.0 million (2001-
$95.0 million) on capital expenditures prior to acquisitions and divestitures.
The capital program to enhance light oil production at Joarcam invested $19.5
million to drill, complete and tie-in 11 Viking Oil wells and construct the
associated production facilities. The Medicine Hat North 50 well shallow natural
gas development program is near completion and additional compression capacity
has been completed at a cost of $8.6 million. Enerplus participated in the
drilling of three natural gas wells at Mount Benjamin, a non-operated property,
at a cost of $4.7 million. Two of the wells were successfully completed with the
third near completion at the end of the quarter.

Capital expenditures are in line with those anticipated for the three and nine
months ended September 30, 2002. The Fund expects annual capital expenditures of
approximately $145.0 million in 2002 which has increased from the original
estimate of $130.0 million as a result of opportunities identified in acquired
and existing properties.

<Table>
<Caption>

                                                                THREE MONTHS                        NINE MONTHS
 CAPITAL EXPENDITURES                                        ENDED SEPTEMBER 30,                ENDED SEPTEMBER 30,
---------------------------------------------------     ------------------------------     -------------------------------
($ millions)                                                2002             2001              2002              2001
                                                        -------------    -------------     -------------     -------------
<S>                                                         <C>              <C>               <C>               <C>
Development drilling and recompletions                      $32.0            $25.9             $60.4             $53.7
Plant and facilities                                         12.8             15.2              34.7              36.2
Land and seismic                                              0.3              0.3               2.0               4.0
Office                                                        1.0              0.5               3.9               1.1
                                                        -------------    -------------     -------------     -------------
Total capital spending                                       46.1             41.9             101.0              95.0
Acquisitions of oil and gas properties                       25.4             57.2              48.3              60.0
Dispositions of non-core oil and gas properties              (0.3)           (34.8)             (2.4)            (54.8)
                                                        -------------    -------------     -------------     -------------
Net capital expenditures                                    $71.2            $64.3            $146.9            $100.2
                                                        =============    =============     =============     =============
</Table>


<Page>

Acquisitions of oil and natural gas properties for the nine months ended
September 30, 2002 are comprised primarily of the acquisition of a 16% working
interest in Oil Sands Lease #24 for $16.4 million, along with the acquisition of
an additional interest in the Medicine Hat Glauconite C property during the
first quarter 2002 for $20.5 million.

Through the remainder of the year, Enerplus will continue to pursue acquisition
opportunities while maintaining a focused effort on the development of existing
reserves that provide attractive potential economic returns to Unitholders.

LIQUIDITY AND CAPITAL RESOURCES

Enerplus' long-term debt as at September 30, 2002 of $362.5 million, which was
comprised of bank credit facilities of $94.2 million and senior unsecured notes
of $268.3 million was lower than long-term debt of $412.6 million as at December
31, 2001. The decrease in debt can be attributed to the equity issue on
September 12, 2002 combined with cash from operations that has been withheld for
debt repayments.
<Table>
<Caption>
                                                                NINE MONTHS ENDED                 YEAR ENDED
FINANCIAL LEVERAGE AND COVERAGE RATIOS                          SEPTEMBER 30, 2002            DECEMBER 31, 2001
----------------------------------------------------------    -----------------------    -----------------------------
<S>                                                                   <C>                           <C>
Long-term debt to funds flow from operations                          1.3 x                         1.2 x
Funds flow from operations to interest expense*                       16.4 x                        19.3x
Long-term debt to long-term debt plus equity                           21%                           23%
</Table>

*Funds flow from operations to interest expense ratio is based on the first
 nine months of 2002 plus the last three months of 2001.

During the second quarter of 2002, Enerplus diversified its debt portfolio
through the issuance of US$175 million senior, unsecured notes with a coupon
rate of 6.62% priced at par (the "Notes"). The Notes have a final maturity of
June 19, 2014, with amortizing payments of 20% per annum on each of the five
anniversary dates commencing on June 19, 2010. Concurrent with the issuance of
the Notes, Enerplus swapped the US$175 million into Canadian dollar denominated
floating rate debt at an exchange rate of 1.5333 for gross proceeds of $268.3
million at a floating interest rate, based on Canadian three month banker's
acceptances, plus 1.18%. This cross currency swap on the senior unsecured notes
represented a mark-to-market gain of $40.0 million as at September 30, 2002. The
Notes provide the Fund with a new source of financing and the assurance of
long-term credit commitments at attractive rates.

On September 12, 2002, Enerplus closed an equity offering of 4,750,000 trust
units at a price of $26.85 per trust unit for gross proceeds of $127,538,000
(net $120,886,000). These proceeds were used to reduce the amounts outstanding
on the bank credit facilities.

As at September 30, 2002, Enerplus had a borrowing base limit of $620 million
with respect to its bank credit facilities and senior unsecured debentures. This
limit is based on the bank's evaluation of the value of Enerplus' proven oil and
gas reserves. As of November 7, 2002, this limit was increased to $700 million.
As a result, Enerplus' bank credit facilities were increased by $80 million from
$351.7 million to $431.7 million.

On October 21, 2002, Enerplus closed the acquisition of Celsius Energy Resources
Ltd. for total consideration of $165.9 million. This acquisition was financed
from Enerplus' revolving credit facility.


TRUST UNIT INFORMATION

Enerplus had 74,751,000 trust units and no warrants outstanding at September 30,
2002 compared to 65,044,000 trust units and 2,238,000 warrants at September 30,
2001. The weighted average number of trust units outstanding during the third
quarter of 2002 was 70,850,000 (2001 - 64,776,000). The weighted average number
of trust units outstanding for the nine months ended September 30, 2002 was
70,066,000 (2001 - 50,738,000).


<Page>


TAXABILITY OF DISTRIBUTIONS

In the current commodity price environment, Enerplus expects that approximately
65% of the distributions paid to Canadian Unitholders in 2002 will be taxable
and the remaining 35% will be treated as a tax deferred return of capital.


FORWARD-LOOKING STATEMENTS

This discussion and analysis contains forward-looking statements relating to
future events or future performance. In some cases, forward-looking statements
can be identified by terminology such as "may", "will", "should", "expects",
"projects", "plans", "anticipates" and similar expressions. These statements
represent management's expectations or beliefs concerning, among other things,
future operating results and various components thereof or the economic
performance of Enerplus. The projections, estimates and beliefs contained in
such forward-looking statements necessarily involve known and unknown risks and
uncertainties, including the business risks discussed above, which may cause
actual performance and financial results in future periods to differ materially
from any projections of future performance or results expressed or implied by
such forward-looking statements. Accordingly, readers are cautioned that events
or circumstances could cause results to differ materially from those predicted.