Document:

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                                                                     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

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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

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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.

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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.<Page>

                                                                     Exhibit 4.8

ENERPLUS RESOURCES FUND
CONSOLIDATED BALANCE SHEET
--------------------------------------------------------------------------------
<Table>
<Caption>

($ THOUSANDS)  (UNAUDITED)                                    SEPTEMBER 30, 2002              DECEMBER 31, 2001
                                                           -------------------------     -----------------------------
<S>                                                              <C>                            <C>
ASSETS
Current assets
  Cash and cash equivalents                                      $       3,471                  $          979
  Accounts receivable                                                   75,638                         100,089
  Other current                                                          3,377                           4,869
                                                           -------------------------     -----------------------------
                                                                        82,486                         105,937
                                                           -------------------------     -----------------------------

Property, plant and equipment                                        2,814,368                       2,667,504
Accumulated depletion and depreciation                                (643,572)                       (489,188)
                                                           -------------------------     -----------------------------
                                                                     2,170,796                       2,178,316
                                                           -------------------------     -----------------------------

Deferred charges (Note 4)                                                1,847                             -
                                                           -------------------------     -----------------------------

                                                                    $2,255,129                      $2,284,253
                                                           =========================     =============================

LIABILITIES
Current liabilities
  Accounts payable                                                $     76,582                     $    72,341
  Distributions payable to unitholders                                  22,426                          20,860
  Payable to related party (Note 3)                                     10,392                           7,915
                                                           -------------------------     -----------------------------
                                                                       109,400                         101,116
                                                           -------------------------     -----------------------------

Long-term debt (Note 4)                                                362,458                         412,589
Future income taxes                                                    314,222                         333,560
Accumulated site restoration                                            58,538                          55,403
Deferred credits                                                         4,848                           6,591
Payable to related party (Note 3)                                        1,525                           1,909
                                                           -------------------------     -----------------------------
                                                                       741,591                         810,052
                                                           -------------------------     -----------------------------

EQUITY
  Unitholders' capital (Note 2)                                      1,958,521                       1,826,507
  Accumulated income                                                   389,069                         324,570
  Accumulated cash distributions                                      (943,452)                       (777,992)
                                                           -------------------------     -----------------------------
                                                                     1,404,138                       1,373,085
                                                           -------------------------     -----------------------------

                                                                    $2,255,129                      $2,284,253
                                                           =========================     =============================
Number of Trust Units outstanding
(thousands)                                                             74,751                          69,532
                                                           =========================     =============================
</Table>

<Page>

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF INCOME
--------------------------------------------------------------------------------
<Table>
<Caption>
($ THOUSANDS EXCEPT PER UNIT AMOUNTS)                      THREE MONTHS ENDED                         NINE MONTHS ENDED
(UNAUDITED)                                                   SEPTEMBER 30                              SEPTEMBER 30
                                                  --------------------------------------    --------------------------------------
                                                       2002                  2001                 2002                 2001
                                                  ----------------     -----------------    -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>                  <C>
REVENUES
  Oil and gas sales                                     $151,286             $163,824             $428,408             $492,420
  Crown royalties                                        (21,161)             (24,231)             (66,013)             (89,536)
  Freehold and other royalties                            (7,823)              (8,713)             (22,502)             (26,032)
                                                  ----------------     -----------------    -----------------    -----------------
                                                         122,302              130,880              339,893              376,852
  Interest and other income                                   31                  110                  338                  680
                                                  ----------------     -----------------    -----------------    -----------------
                                                         122,333              130,990              340,231              377,532
                                                  ----------------     -----------------    -----------------    -----------------

EXPENSES
  Operating                                               34,689               34,717               95,853               81,157
  General and administrative                               3,352                1,633               10,085                6,367
  Management  fees (Note 3)                                7,216                2,497               13,571                6,957
  Interest (Note 5)                                        5,169                5,121               12,705               13,473
  Depletion, depreciation and
    Amortization                                          52,656               55,423              158,906              135,885
                                                  ----------------     -----------------    -----------------    -----------------
                                                         103,082               99,391              291,120              243,839
                                                  ----------------     -----------------    -----------------    -----------------

Income before taxes                                       19,251               31,599               49,111              133,693
Capital taxes                                              1,294                1,352                3,950                3,624
Future income tax                                        (11,124)               5,106              (19,338)             (13,260)
                                                  ----------------     -----------------    -----------------    -----------------
NET INCOME                                              $ 29,081             $ 25,141             $ 64,499             $143,329
                                                  ================     =================    =================    =================

Net income per trust unit
  Basic                                                  $0.41                $0.39                $0.92                $2.82
                                                  ================     =================    =================    =================
  Diluted                                                $0.41                $0.39                $0.92                $2.82
                                                  ================     =================    =================    =================

Weighted average number of
  Units outstanding (thousands)
  Basic                                                   70,850               64,776               70,066               50,738
                                                  ================     =================    =================    =================
  Diluted                                                 71,019               64,853               70,181               50,817
                                                  ================     =================    =================    =================
</Table>

CONSOLIDATED STATEMENT OF ACCUMULATED INCOME
--------------------------------------------------------------------------------
<Table>
<Caption>
                                                           THREE MONTHS ENDED                         NINE MONTHS ENDED
($ THOUSANDS), (UNAUDITED)                                    SEPTEMBER 30                              SEPTEMBER 30
                                                  --------------------------------------    --------------------------------------
                                                       2002                  2001                 2002                 2001
                                                  ----------------     -----------------    -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>                  <C>
Accumulated income, beginning
  of period                                             $359,988             $262,489             $324,570             $144,301
Net income                                                29,081               25,141               64,499              143,329
                                                  ----------------     -----------------    -----------------    -----------------
Accumulated income, end of
  Period                                                $389,069             $287,630             $389,069             $287,630
                                                  ================     =================    =================    =================
</Table>

<Page>

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF CASH FLOWS
--------------------------------------------------------------------------------
<Table>
<Caption>
                                                           THREE MONTHS ENDED                         NINE MONTHS ENDED
($ THOUSANDS), (UNAUDITED)                                    SEPTEMBER 30                              SEPTEMBER 30
                                                  --------------------------------------    --------------------------------------
                                                       2002                  2001                 2002                 2001
                                                  ----------------     -----------------    -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>                  <C>
OPERATING ACTIVITIES
Net income                                              $ 29,081             $ 25,141             $ 64,499             $143,329
Depletion, depreciation and                               52,656
  Amortization                                                                 55,423              158,906              135,885
Future income tax                                        (11,124)               5,106              (19,338)             (13,260)
Site restoration and abandonment
  Costs incurred                                          (1,023)                (719)              (3,130)              (1,343)
                                                  ----------------     -----------------    -----------------    -----------------
Funds flow from operations                                69,590               84,951              200,937              264,611
Decrease (increase) in non-cash
  Operating working capital                                1,787               (7,565)              21,832              (35,779)
                                                  ----------------     -----------------    -----------------    -----------------
                                                          71,377               77,386              222,769              228,832
                                                  ----------------     -----------------    -----------------    -----------------
FINANCING ACTIVITIES
Issue of trust units, net of
  Issue costs                                            124,591               11,253              131,274               45,845
Cash distributions to unitholders                        (61,323)             (92,677)            (163,894)            (252,512)
Increase (decrease) in long-term
  Debt                                                   (78,351)              79,768              (50,131)              93,325
Payment to related party (Note 3)                           (128)                (127)                (384)                (127)
Deferred charges                                               -                    -               (1,892)                   -
                                                  ----------------     -----------------    -----------------    -----------------
                                                         (15,211)              (1,783)             (85,027)            (113,469)
                                                  ----------------     -----------------    -----------------    -----------------
INVESTING ACTIVITIES
Property, plant and equipment                            (54,366)            (101,495)            (137,696)            (156,323)
Proceeds on sale of property,
  Plant and equipment                                        308               34,755                2,446               61,581
Corporate acquisitions                                         -               (8,792)                   -              (20,594)
                                                  ----------------     -----------------    -----------------    -----------------
                                                         (54,058)             (75,532)            (135,250)            (115,336)
                                                  ----------------     -----------------    -----------------    -----------------

Increase in cash                                           2,108                   71                2,492                   27
Cash, beginning of period                                  1,363                  802                  979                  846
                                                  ----------------     -----------------    -----------------    -----------------
Cash, end of period                                     $  3,471            $     873             $  3,471            $     873
                                                  ================     =================    =================    =================

Funds flow from operations per unit                      $0.98                $1.31                $2.87                $5.22
                                                  ================     =================    =================    =================

SUPPLEMENTARY CASH FLOW
INFORMATION
    Cash income taxes paid                          $          -         $          -         $          -       $            -
    Cash interest paid                                  $  2,099             $  5,373             $  9,483            $  13,278
                                                  ================     =================    =================    =================
</Table>

CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS
--------------------------------------------------------------------------------
<Table>
<Caption>
                                                           THREE MONTHS ENDED                         NINE MONTHS ENDED
($ THOUSANDS), (UNAUDITED)                                    SEPTEMBER 30                              SEPTEMBER 30
                                                  --------------------------------------    --------------------------------------
                                                       2002                  2001                 2002                 2001
                                                  ----------------     -----------------    -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>                  <C>
Accumulated cash distributions,
  Beginning of period                                   $881,863             $619,051             $777,992             $447,158
Cash distributions to unitholders                         61,589               87,712              165,460              259,605
                                                  ----------------     -----------------    -----------------    -----------------
Accumulated cash distributions,
  end of period                                         $943,452             $706,763             $943,452             $706,763
                                                  ================     =================    =================    =================
</Table>

<Page>

SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS AND THOUSANDS OF UNITS
EXCEPT PER UNIT AMOUNTS)
--------------------------------------------------------------------------------

1.       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, 2001 except as stated below.
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, 2001. The disclosures
provided below are incremental to those included in the 2001 annual consolidated
financial statements.

(a)      The accounting of the merger of EnerMark Income Fund ("EnerMark") and
         Enerplus Resources Fund ("Enerplus") which occurred on June 21, 2001
         ("the Merger"), applied the reverse takeover form of the purchase
         method of accounting for business combinations. Accordingly, these
         consolidated financial statements of the Fund include the accounts of
         the merged Fund for the nine months ended September 30, 2002 but the
         comparative figures for the prior year include the accounts of EnerMark
         as at and for the nine months ended September 30, 2001, plus the
         results of Enerplus from June 21, 2001 to September 30, 2001.

         All numbers of trust units and Warrants up to the June 21, 2001 Merger
         date have been restated using the merger exchange ratio of 0.173
         EnerMark unit for each Enerplus unit (the "Merger Exchange Ratio").

(b)      Effective for the fiscal years beginning on or after January 1, 2002,
         the Fund adopted the recommendations of the CICA on accounting for
         stock-based compensation which apply to new rights granted on or after
         that date. The Fund has elected to continue to measure compensation
         cost based on the intrinsic value of the award at the date of the grant
         and recognize that cost over the vesting period. As the exercise price
         of the rights granted approximates the market price of the trust units
         at the grant date, no compensation cost has been provided in the
         consolidated statement of income.

         The exercise price of the rights granted under the Fund's rights plan
         may be reduced in future periods in accordance with the terms of the
         rights plan. The amount of the reduction cannot be reasonably
         determined as it is dependent upon a number of factors including, but
         not limited to, future prices received on the sale of oil and natural
         gas, future production of oil and natural gas, determination of the
         amounts to be withheld from future distributions to fund capital
         expenditures and the purchase and sale of property, plant and
         equipment. Therefore, it is not possible to determine a fair value for
         the rights granted under the plan.

2.       FUND CAPITAL

         (a) UNITHOLDERS' CAPITAL

   AUTHORIZED:  UNLIMITED NUMBER OF TRUST UNITS
<Table>
<Caption>
                                                   SEPTEMBER 30, 2002                    DECEMBER 31, 2001
                                            ---------------------------------    --------------------------------
ISSUED:  (THOUSANDS)                           UNITS             AMOUNT              UNITS            AMOUNT
                                            ------------    -----------------    ------------     ---------------
<S>                                             <C>            <C>                  <C>               <C>
Balance, beginning of period                    69,532         $1,826,507           40,925            $1,050,986
Issued for cash:
  Pursuant to public offerings                   4,750            120,886            4,313               101,039
  Pursuant to Option Plans                          98              1,905              135                 2,530
  Pursuant to exercise of warrants                   -                  -            1,197                33,319
  Pursuant to expiry of warrants                     -                  -                -                 2,846
Issued pursuant to the deemed
  Acquisition of Enerplus (Note 1)                   -                  -           20,863               582,364
</Table>

<Page>

<Table>
<S>                                              <C>                <C>              <C>                <C>
  Issued pursuant to the management
  agreement (Note 3)                                 -                  -              173                 5,000
Distribution Reinvestment & Unit Purchase
Plan                                               340              8,483              659                16,577
Issued for acquisition of
  Property interests                                31                740            1,267                31,846
                                            ------------    -----------------    ------------     ---------------
Balance, end of period                          74,751         $1,958,521           69,532            $1,826,507
                                            ============    =================    ============     ===============
</Table>

         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).

         (b) TRUST UNIT OPTION PLAN

         As at September 30, 2002, 150,000 options issued pursuant to the Trust
         Unit Option Plan were outstanding, representing 0.2% of the total units
         outstanding. Activity for the options issued pursuant to the option
         plan is summarized as follows:

<Table>
<Caption>
                                            SEPTEMBER 30, 2002                     DECEMBER 31, 2001
                                     ----------------------------------    ----------------------------------
                                                        WEIGHTED                               WEIGHTED
                                                        AVERAGE                                AVERAGE
(THOUSANDS EXCEPT                    NUMBER OF          EXERCISE           NUMBER OF           EXERCISE
PER UNIT AMOUNTS)                    OPTIONS            PRICE              OPTIONS             PRICE
                                     ---------------    ---------------    ---------------     --------------
<S>                                         <C>             <C>                  <C>               <C>
Options outstanding at
  beginning of period                       264             $20.93               363(1)            $21.03
Exercised                                   (98)            $19.55               (55)              $21.94
Cancelled                                   (16)            $22.73               (44)              $20.47
                                     ---------------                       ---------------
Options outstanding at
  end of period                             150             $21.75               264               $20.93
                                     ===============                       ===============
Options exercisable at
  end of period                             119                                   99
                                     ---------------                       ---------------
</Table>

(1) Number of options representing the balance at June 21, 2001 after
    the Merger of EnerMark and Enerplus.

No new options have been granted under the Trust Unit Option Plan as this plan
was superseded by the Trust Unit Rights Incentive Plan discussed below.

(c) TRUST UNIT RIGHTS INCENTIVE PLAN

As at September 30, 2002, a total of 1,348,000 rights were issued (2,740,000
reserved) pursuant to the Trust Unit Rights Incentive Plan of which none are
exercisable. Under the Incentive Plan, distributions per trust unit to Enerplus
Unitholders in a calendar quarter which represent a return of more than 2.5% of
the net property, plant and equipment of Enerplus at the end of such calendar
quarter would result in a reduction in the exercise price of the rights. Based
on second and third quarter 2002 results, the exercise price has been calculated
to be reduced by $0.07 per trust unit (effective October 2002) and $0.14 per
trust unit (effective January 2003) respectively.

As it is not possible to determine the fair value of rights granted under the
plan, compensation costs for pro forma disclosure purposes has been determined
based on the excess of the unit price over the exercise price at the date of the
financial statements. For the three and nine months ended September 30, 2002,
net income would be reduced by $150,000 and $183,000, for the estimated
compensation cost associated with rights granted under the plan on or after
January 1, 2002 with a negligible impact on net income per trust unit during
these periods.

<Page>

Activity for the rights issued pursuant to the Incentive Plan is as follows:
<Table>
<Caption>
                                                  SEPTEMBER 30, 2002                      DECEMBER 31, 2001
                                           ----------------------------------     ----------------------------------
                                                              WEIGHTED                               WEIGHTED
                                                              AVERAGE                                AVERAGE
(THOUSANDS EXCEPT                          NUMBER OF          EXERCISE            NUMBER OF          EXERCISE
PER UNIT AMOUNTS)                          RIGHTS             PRICE               RIGHTS             PRICE
                                           ---------------    ---------------     ---------------    ---------------
<S>                                            <C>                <C>                   <C>              <C>
Rights outstanding at
  Beginning of period                           1,318             $24.50                    -              -
Granted                                           145             $26.66                1,360            $24.50
Cancelled                                        (115)            $24.47                  (42)           $24.50
                                           ---------------                        ---------------
Rights outstanding at
  End of period                                 1,348             $24.63                1,318            $24.50
                                           ===============                        ===============
</Table>

3.       RELATED PARTY TRANSACTIONS

Management, advisory and administration services are supplied to the Fund on a
fee and cost reimbursement basis, pursuant to an agreement with Enerplus Global
Energy Management Company ("EGEM"). Management fees of $13,571,000 are reported
on the consolidated statement of income for the nine months ended September 30,
2002. This included earned base management fees of $6,291,000 and accrued
performance fees of $7,280,000. The performance fees are not determined until
December 31, 2002, and as such, this amount may increase or decrease throughout
the remainder or the year. As at September 30, 2002, $9,883,000 was payable to
EGEM, pursuant to this agreement.

In addition, pursuant to a share purchase agreement related to the Merger, the
Fund acquired shares of Enerplus Resources Corporation from EGEM for $2,545,000
payable over five years in quarterly installments of $127,000 through a
reduction of management fees. At September 30, 2002, the indebtedness remaining
pursuant to this agreement was $2,035,000 of which $509,000 has been classified
as current.

In addition to the transactions described above, Enerplus has entered into
financial instrument contracts at prevailing market rates with an indirect
subsidiary of El Paso Corporation, the ultimate parent of EGEM, as described in
Note 5.

4.       LONG-TERM DEBT
<Table>
<Caption>
                                                         SEPTEMBER 30, 2002           DECEMBER 31, 2001
                                                      -------------------------       ------------------------------
<S>                                                           <C>                                 <C>
Bank credit facilities                                         $94,130                            $412,589
Senior unsecured notes                                         268,328                                   -
                                                      -------------------------       ------------------------------
Total long-term debt                                          $362,458                            $412,589
                                                      =========================       ==============================
</Table>

The senior unsecured notes (the "Notes") were issued on June 19, 2002 in the
amount of US$175,000,000. They have a final maturity of June 19, 2014 and bear
interest at 6.62% per annum, with interest paid semi-annually on June 19 and
December 19 of each year. The Note Purchase Agreement requires the Fund to make
five annual amortizing principal repayments of 20% of the initial principal
amount, commencing on June 19, 2010.

Concurrent with the issuance of the Notes, the Fund entered into a cross
currency swap, with a syndicate of major 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
banker's acceptances, plus 1.18%. Costs incurred in connection with issuing the
Notes, in the amount of $1,892,000, are being amortized over the term of the
Notes. As at September 30, 2002, the amount not amortized associated with these
costs was $1,847,000.

Subsequent to September 30, 2002 the Fund's borrowing base was increased to
$700,000,000. The increase resulted in the amount of credit available under the
bank credit facilities (the "Facilities") being increased to $431,672,000 from
$351,672,000. The Facilities remain unsecured and consist of a $402,000,000
revolving committed line with an incremental two-year term, and a $29,672,000
demand

<Page>

operating line. Various borrowing options are available under the Facilities
including prime rate based advances and banker's acceptance loans.

5.       FINANCIAL INSTRUMENTS

The Fund uses various types of financial instruments to manage the risk related
to fluctuating commodity prices. The fair values of these instruments are based
on an approximation of the amounts that would have been paid to or received from
counterparties to settle the instruments outstanding as at September 30, 2002
with reference to forward prices and mark-to-market valuations provided by
independent sources. The Fund may be exposed to losses in the event of default
by the counterparties to these instruments. This credit risk is controlled by
the Fund through the selection of financially sound counterparties.

INTEREST RATE AND CROSS CURRENCY SWAPS:

In addition to the cross currency swap described in Note 4, the Fund has entered
into various interest rate swaps on a notional amount of bank debt, as follows:
<Table>
<Caption>
                                                                     NOTIONAL
TERM                                                                  AMOUNT                     FIXED RATE (1)
----------------------------------------------------         -----------------------         -----------------------
<S>                                                               <C>                               <C>
January 18, 2002 to January 18, 2005                              $25 million                       3.89%
June 3, 2002 to June 3, 2005                                       25 million                       4.70%
June 4, 2002 to June 4, 2005                                       25 million                       4.65%
                                                             -----------------------
                                                                  $75 million
                                                             =======================
</Table>
(1) Before banking fees that are expected to range between 0.85% and 1.05%.

The mark-to-market values of the $75.0 million interest rate swaps as at
September 30, 2002, represent an unrealized loss of $2.0 million. The
mark-to-market value of the cross currency interest rate swap related to the
Senior Unsecured Notes as at September 30, 2002 represented an unrealized gain
of $40.0 million.

CRUDE OIL:

Enerplus has entered into the following financial option contracts on its gross
crude oil production that are designed to reduce a downward impact of crude oil
prices. The remaining costs to be amortized associated with these contracts are
approximately $215,000. The mark-to-market value of the financial crude oil
contracts as at September 30, 2002 reflects an unrealized loss of $8,979,000.
<Table>
<Caption>
                                                              WTI CRUDE OIL PRICE US $
                                                              -------------------------------------------------------
                                           VOLUME             SOLD                PURCHASED            SOLD
TERM                                       BBLS/DAY           CALL                PUT                  PUT
--------------------------------------     ---------------    ---------------     ----------------     --------------
<S>                                              <C>             <C>                   <C>                <C>
July 1, 2002 - Dec. 31, 2002
   3-way                                         1,500           US$27.00              US$19.50           US$16.00
   3-way(1)                                      1,500           US$25.00              US$19.50           US$17.00
   3-way                                         2,175           US$27.00              US$19.50           US$17.00
   3-way                                         1,500           US$28.00              US$20.10           US$17.00
   3-way(2)                                      1,500           US$31.00              US$22.00           US$19.50
   3 way(2)                                      1,500           US$30.00              US$24.00           US$21.35
Oct. 1, 2002 - Sept. 30, 2004
   3-way(2)                                      1,500           US$29.00              US$22.00           US$19.25
Jan.1, 2003 - Sept. 30, 2004
   3-way(2)                                      1,500           US$30.00              US$23.00           US$20.00
Jan. 1, 2003 - Dec. 31, 2003
   3-way                                         1,500           US$27.00              US$19.50           US$17.00
   3-way                                         1,500           US$28.00              US$20.15           US$17.00
   3-way(2)                                      1,500           US$28.51              US$22.00           US$19.50
Jan. 1, 2003 - June 30, 2004
   3-way(2)                                      1,500           US$28.00              US$22.50           US$19.60
   3-way(2)                                        500           US$28.00              US$22.50           US$19.90
Jan. 1, 2003 - December 31, 2004
   3-way (3)                                     1,500           US$29.50              US$22.00           US$20.00
</Table>

(1)      The counterparty to this 3-way crude oil option is a subsidiary of El
         Paso Corporation which is the ultimate parent of EGEM (refer to Note 3)
         and the amount receivable/payable with respect to this transaction is
         currently not material. The remaining option premium for this
         instrument is $69,000 and is being amortized over the remaining term.
(2)      Financial option transactions entered into during the third quarter of
         2002.
(3)      Transactions entered into subsequent to September 30, 2002 that are not
         included in the mark-to-market values.

NATURAL GAS:

In addition to the crude oil price protection initiatives described previously,
Enerplus also has physical and financial contracts in place on its gross natural
gas production as described below. The remaining costs to be amortized
associated with these contracts are $0.01 per trust unit or $509,000 in 2002 and
$0.02 per trust unit or $1,694,000 in 2003. The mark-to-market value of the
financial natural gas contracts as at September 30, 2002 reflects an unrealized
loss of $17,981,000.
<Table>
<Caption>
                                 MMCF/DAY                                  AECO $/MCF CDN$
                                 -----------    ----------------------------------------------------------------------
                                 DAILY          SOLD         PURCHASED          SOLD        FIXED        ESCALATED
TERM                             VOLUMES        CALL         PUT                PUT         PRICE        PRICE
-----------------------------    -----------    --------     --------------     --------    --------     -------------
<S>                                 <C>          <C>              <C>            <C>          <C>            <C>
July 1, 2002 - Oct. 31, 2002
  Physical                            3.8          -                -              -          $2.63            -
  Physical                            8.5          -                -              -          $3.97            -
  Collar(1)                           9.5         $5.27            $3.69           -           -               -
  Put(1)                              9.5          -               $3.69           -           -               -
  3-way                               9.5         $4.22            $3.29          $2.37        -               -
July 1, 2002 - Dec. 31, 2002
  Physical                            2.8          -                -              -          $2.64            -
  Physical                            2.0          -                -              -           -              $2.01
  Swap                                3.8          -               $2.90           -           -               -
  Collar                              7.6         $4.22            $3.43           -           -               -
  Collar                              5.7         $4.81            $3.43           -           -               -
  Collar                             14.2         $4.22            $3.32           -           -               -
Nov. 1, 2002 - Dec. 31, 2002
  Collar(1)                           7.1         $5.27            $3.69           -           -               -
  Put(1)                              7.1          -               $3.69           -           -               -
  Call                                9.5         $6.33             -              -           -               -
Nov. 1, 2002 - Mar. 31, 2003
  3-way(2)(3)                         4.8         $7.39            $5.28          $4.22        -               -
  3-way(4)(5)                         4.8         $7.39            $5.28          $4.22        -               -
Jan. 1, 2003 - Mar. 31, 2003
  Call                                9.5         $6.33             -              -           -               -
Jan. 1, 2003 - Oct. 31, 2003
  Physical                            2.8          -                -              -          $2.64            -
  Collar(1)                           7.1         $5.27            $3.69           -           -               -
  Put(1)                              7.1          -               $3.69           -           -               -
Jan. 1, 2003 - Dec. 31, 2003
  Physical                            2.0          -                -              -           -              $2.23
  Swap                                3.8          -               $2.90           -           -               -
  3-way                               9.5         $7.91            $4.27          $3.17        -               -
Jan. 1, 2003 - June 30, 2004
  3-way                               9.5         $7.39            $4.75          $3.17        -               -
Jan. 1, 2003 - Sept. 30, 2004
  3-way(2)                            9.5         $6.67            $4.75          $3.17        -               -
  3-way(2)                            9.5         $7.39            $4.75          $3.69        -               -
Jan. 1, 2003 - Oct. 31, 2006
  Swap (5)                            9.5          -               $5.47           -           -               -
Apr.1, 2003 - Oct. 31, 2003
  Collar(2)                           4.8         $6.25            $4.75           -           -               -
  Collar(5)                           4.8         $6.25            $4.75           -           -               -
Jan. 1, 2004 - Oct. 31, 2004
  Swap                                3.8          -               $2.90           -           -               -
2004 - 2010
  Physical                            2.0          -                -              -           -              $2.33
</Table>

(1)      The counterparty to these natural gas collars and puts is a subsidiary
         of El Paso Corporation which is the ultimate parent of EGEM (refer to
         Note 3) and the amounts receivable/payable with respect to these
         transactions are currently not material. The remaining option premiums
         for these instruments are $2,203,000 and are being amortized over their
         remaining terms.
(2)      Additional transactions entered into during the third quarter of 2002.
(3)      Enerplus sells physical gas at the Month Index less $0.05/Mcf.
(4)      Enerplus sells physical gas at the Month Index less $0.11/Mcf.
(5)      Transactions entered into subsequent to September 30, 2002 that are not
         included in the mark-to-market values.

<Page>

6.       COMMITMENTS AND CONTINGENCIES

The acquisition of the working interest in Oil Sands Lease #24 (Joslyn Creek
Lease) included the assumption of approximately $4,100,000 in contingent project
debt that was comprised of $3,360,000 of principal and approximately $740,000 in
accrued interest. Interest is accrued at the Bank of Canada prime business rate
and is not compounded. The debt is contingent on both production and pricing
hurdles with respect to development on the lease. As it is too early in the
development of this project to determine if these hurdles will be satisfied, the
contingent debt has not been accrued in the consolidated financial statements.

7.       SUBSEQUENT EVENT

Subsequent to September 30, 2002, the Fund acquired all of the issued and
outstanding shares of Celsius Energy Resources Ltd., a private oil and gas
company, for total cash consideration of approximately $165.9 million including
working capital adjustments. The acquisition will be accounted for by the
purchase method with the results of operations included in the consolidated
financial statements of the Fund from the closing date of October 21, 2002.

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