<PAGE>

                                                                    EXHIBIT 4.4

Momentum

o Enerplus Unitholders received record cash distributions in 2001

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis of financial results is to be read in
conjunction with the audited consolidated financial statements as at, and for
the years ended December 31, 2001 and 2000, and is based on information
available to March 1, 2002. All amounts are stated in Canadian dollars unless
otherwise specified.

2001 HIGHLIGHTS

o    On June 21, 2001, the Unitholders of Enerplus Resources Fund and EnerMark
     Income Fund agreed to combine the two funds and continue as Enerplus
     Resources Fund. This created North America's largest and most liquid
     conventional oil and natural gas income fund with an enterprise value of
     approximately $2 billion.

o    In connection with the combination of the two funds, Enerplus restructured
     its management fee to better align the interests of the Manager and the
     Unitholders by eliminating acquisition and divestment fees and replacing
     them with performance incentive fees.

o    Aside from the reverse takeover combination of Enerplus and EnerMark,
     acquisitions net of dispositions of producing oil and gas properties
     totaled $8.9 million during the year ($77.4 million in acquisitions less
     $68.5 million in dispositions of non-core properties). The Fund avoided
     high cost acquisitions in a high priced environment for much of 2001 as a
     result of its disciplined bidding strategy.

o    Enerplus invested $143 million in development projects in 2001, drilling a
     record 350 net wells.

o    Enerplus' commodity price risk management program generated a net gain of
     $50.1 million for the year, demonstrating the value of such a program
     during periods of price volatility.

o    On November 15, 2001, the Fund issued 4,312,500 Trust Units at $24.75 per
     unit in a successful Canadian equity issue.

COMBINATION OF ENERMARK AND ENERPLUS

On June 21, 2001, the respective Unitholders of the EnerMark Income Fund
("EnerMark") and the Enerplus Resources Fund ("Enerplus") overwhelmingly
approved a merger combining the two funds. 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 has been accounted for using the reverse
takeover 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.

IMPORTANT INFORMATION REGARDING COMPARATIVE FINANCIAL STATEMENTS

With the reverse takeover method of accounting, the audited consolidated
financial statements presented herein include the accounts of EnerMark as at,
and for the twelve months ended December 31, 2001, plus the results of Enerplus
for the 193-day period from June 21, 2001 to December 31, 2001. In addition, the
historical comparative financial information for the year 2000 presented in the
audited consolidated financial statements is solely that of EnerMark.

In other words, the financial statements do not reflect the pre-acquisition
Enerplus results for the period from January 1, 2001 to June 20, 2001, nor do
they include the pre-acquisition results of Enerplus for the year ending
December 31, 2000.

The remaining discussion and analysis refers to Enerplus as the combined Fund,
and information included herein has been restated, as applicable, to reflect the
Trust Unit exchange ratio of 1.000 EnerMark Unit for 0.173 Enerplus Unit,
pursuant to the reverse takeover.

Comparison of 2001 results with those of 2000 is also complicated by the fact
that EnerMark, as predecessor to Enerplus, completed five major acquisitions
during 2000. Accordingly, the 2001 financial results include a full year of
operations for these acquisitions, while the 2000 results reflect only a
partial-year impact, commencing on the closing date of each acquisition as set
forth below:


<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------- ------------------ -----------------
Corporate and Property Acquisitions                                                     ($ millions)      Closing Date
--------------------------------------------------------------------------------- ------------------ -----------------
<S>                                                                                     <C>              <C>
Enerplus Resources Fund                                                                         $601     Jun. 21, 2001
Cabre Exploration Ltd. (purchase of remaining 11.35% interest)                                    32      Jan. 8, 2001
Cabre Exploration Ltd. (purchase of 88.65% interest)                                             260     Dec. 31, 2000
EBOC Energy Ltd.                                                                                 148      Sep. 1, 2000
Pursuit Resources Corp.                                                                           82      Apr. 3, 2000
Hanna/Garden Plains                                                                               35     Feb. 28, 2000
Western Star Exploration Ltd.                                                                     22      Jan. 7, 2000
--------------------------------------------------------------------------------- ------------------ -----------------
</TABLE>

RESULTS OF OPERATIONS

PRODUCTION

As a result of changing practices in the oil and gas industry in Canada,
Enerplus has adopted the standard of 6 Mcf:1 barrel of oil equivalent when
converting natural gas to barrels of oil equivalent ("BOE"). In accordance with
Canadian practice, production volumes, reserve volumes and revenues are reported
on a gross basis, before deduction of Crown and other royalties, unless
otherwise indicated.

Daily production averaged 54,015 BOE per day during 2001, representing a 74%
increase over production volumes of 31,112 BOE per day the previous year. The
increase is attributed to the reverse takeover of Enerplus by EnerMark on June
21, 2001, as well as the previously mentioned acquisitions during 2000. The
acquisitions in 2000 had a full year impact on 2001 production, but only a
partial-year impact on 2000 production, relative to the respective closing date
of the acquisition.

Enerplus' production is widely distributed across more than 250 properties in
Alberta, Saskatchewan and British Columbia. The largest 10 properties account
for 31% of Enerplus' production. This wide distribution minimizes the risk that
production might be materially impacted by the performance of a few major
properties.

Average production volumes for the years ended December 31, 2001 and 2000 are
outlined below:

<TABLE>
<CAPTION>
--------------------------------------------------------------- ------------------ ----------------- -----------------
Daily Production Volumes                                                   2001(1)              2000          % Change
--------------------------------------------------------------- ------------------ ----------------- -----------------
<S>                                                                        <C>               <C>              <C>
Natural gas (Mcf/day)                                                      176,671           101,473               74%
Crude oil (bbls/day)                                                        20,592            12,089               70%
Natural gas liquids (bbls/day)                                               3,978             2,111               88%
Total daily sales (BOE/day)                                                 54,015            31,112               74%
--------------------------------------------------------------- ------------------ ----------------- -----------------
</TABLE>

..2001 production reflects only 193 days of the post-merger Enerplus production
(from June 21, 2001 to December 31, 2001) after the date of the reverse takeover

Enerplus' exit production rate averaged 62,300 BOE per day for the month of
December 2001, with a weighting of 56% natural gas, 37% crude oil, and 7%
natural gas liquids. Production is currently expected to average 61,000 BOE per
day in 2002, after considering a full-year impact from the reverse takeover of
Enerplus and a forecast $130 million in development capital spending, but
without taking into account any further acquisitions.

PRICING AND PRICE RISK MANAGEMENT

The average price that Enerplus received for its natural gas (before hedging)
increased 9% from $4.52/Mcf in 2000 to $4.91/Mcf in 2001. In comparison, the
AECO monthly index increased 25% from $5.02/Mcf in 2000 to $6.30/Mcf in 2001 and
the NYMEX index price increased 12% from $3.91/Mcf in 2000 to $4.38/Mcf in 2001.
Enerplus' realized gas prices did not increase as much as the reference indices
due to:

o    Long-term fixed price physical delivery contracts representing
     approximately 5% of production that were priced below prevailing index
     prices in 2001; and


<PAGE>

o    Sales to aggregators that were also priced below prevailing indices in 2001
     because they reflect a basket of fixed, floating, and downstream delivery
     contracts.

The average price that Enerplus received for its crude oil (before hedging)
decreased 15% from CDN$35.86/bbl in 2000 to CDN$30.48/bbl in 2001. This reflects
a comparable 14% decline in the pricing of benchmark West Texas Intermediate
(WTI) crude oil. Enerplus benefited from the weaker Canadian exchange rate and a
lighter average blend of crude oil as a result of recent acquisitions, however,
these advantages were offset by wider price differentials on heavier streams of
crude oil during the year.

The realized prices for natural gas liquids ("NGLs") decreased 4% from the
previous year to average $31.12/bbl in 2001. However, the price of NGLs as a
proportion of Enerplus' crude oil price increased from 90% in 2000 to 102% in
2001 reflecting significantly higher values attributed to ethane production in
the first half of 2001.

<TABLE>
<CAPTION>
---------------------------------------------------------------------- --------------- --------------- ---------------
Average Selling Price (CDN$) Before the Effects of Hedging                        2001            2000        % Change
---------------------------------------------------------------------- --------------- --------------- ---------------
<S>                                                                             <C>             <C>           <C>
Natural gas (per Mcf)                                                           $ 4.91          $ 4.52             9%
Crude oil (per bbl)                                                              30.48           35.86           (15)%
Natural gas liquids (per bbl)                                                    31.12           32.33            (4)%
TOTAL DAILY SALES (PER BOE)                                                     $29.89          $30.94            (3)%
---------------------------------------------------------------------- --------------- --------------- ---------------
---------------------------------------------------------------------- --------------- --------------- ---------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------- --------------- --------------- ---------------
Benchmark Pricing                                                                 2001            2000        % Change
---------------------------------------------------------------------- --------------- --------------- ---------------
<S>                                                                            <C>             <C>            <C>
AECO natural gas (per Mcf)                                                     $  6.30         $  5.02            25%
NYMEX natural gas (US$ per Mcf)                                                   4.38            3.91            12%
WTI crude oil (US$ per bbl)                                                      25.97           30.19           (14)%
CDN$/US$ exchange rate                                                         $0.6458         $0.6736            (4)%
---------------------------------------------------------------------- --------------- --------------- ---------------
</TABLE>

Enerplus has an on-going commodity price risk management program that is
designed to provide price protection on a portion of its future production in
the event of adverse commodity price movement, while retaining significant
exposure to upside price movements. 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.

In 2001, Enerplus realized a gain of $50.1 million as a result of its price risk
management program, as outlined below:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------- --------------- --------------
Opportunity Gain (Loss) from Financial Hedging ($ millions)                                      2001           2000
------------------------------------------------------------------------------------- --------------- --------------
<S>                                                                                             <C>            <C>
Crude oil                                                                                       $ 5.5         $ (9.6)
Natural gas                                                                                      44.6            0.5
                                                                                      --------------- --------------
Net hedging opportunity gain (loss)                                                             $50.1         $ (9.1)
                                                                                      --------------- --------------
                                                                                      --------------- --------------
Net gain (loss) per bbl crude oil                                                               $0.73         $(2.19)
Net gain (loss) per Mcf natural gas                                                             $0.69         $ 0.01
------------------------------------------------------------------------------------- --------------- --------------
------------------------------------------------------------------------------------- --------------- --------------
</TABLE>

Enerplus' commodity risk management position as at December 31, 2001 is
described in Note 8 to the financial statements. Commodity price risk is managed
through fixed price physical delivery contracts and financial instruments such
as forward contracts. The net receipts or payments arising from the forward
contracts are recognized in income as a component of oil and gas sales during
the same period as the corresponding hedge position. At December 31, 2001,
Enerplus had $4.6 million in deferred costs related to forward contracts that
will be amortized over the remaining life of those instruments. The
mark-to-market value of the financial forward contracts represented an
unrealized loss of $0.4 million with reference to year-end prices and forward
markets.


<PAGE>

Subsequent to year end, on January 8, 2002, Enerplus entered into an additional
3-way financial option on 1,500 bbls/day of oil from April 2002 to December
2003. Under the terms of this option Enerplus purchased a WTI put at
US$19.50/bbl, sold a WTI call at US$27.00/bbl and sold a WTI put at
US$17.00/bbl. Enerplus also entered into a 3-way option on 9,480 Mcf/day of
natural gas for the period from April to October 2002, selling an AECO call at
$4.22/Mcf, purchasing an AECO put at $3.29/Mcf and selling an AECO put at
$2.37/Mcf. The cost of this gas price protection was mitigated by selling an
AECO call at $6.33/Mcf for the period from November 2002 to March 2003.

In the future, Enerplus intends to continue to manage its commodity price
exposure in a similar manner with the objective of establishing downside price
protection at a reasonable cost, while maintaining exposure to improving prices.
The future gain or loss from such a program depends on forward markets and
future prices. Readers are cautioned that the significant hedging gains
experienced in 2001 are not expected to be replicated in 2002.

REVENUES

Crude oil and natural gas revenues, including hedging gains, were $639.4 million
for the year ended December 31, 2001, which was 86% higher than the $343.2
million reported for the year ended December 31, 2000. This substantial increase
was due to the reverse takeover of Enerplus on June 21, 2001, as well as the
acquisitions of Cabre, EBOC, Pursuit, and Western Star and the acquisition of
the Hanna/Garden Plains property during 2000. The acquisitions in 2000 had a
full year impact on 2001 revenues, but only a partial-year impact on 2000
revenues, depending on the closing date of the acquisition. Enerplus' 2001
increase in revenues was primarily the result of lighter production volumes and
hedging gains offset by a slight reduction in prices as described in the table
below.

<TABLE>
<CAPTION>
-------------------------------------------------------------- -------------- -------------- ------------- -----------
                                                                    Crude Oil            NGL   Natural Gas       Total
Analysis of Sales Revenues ($ millions)                              Revenues       Revenues      Revenues    Revenues
-------------------------------------------------------------- -------------- -------------- ------------- -----------
<C>                                                                 <C>             <C>        <C>            <C>
2000 Sales Revenues                                                    $149.0          $25.0        $169.2      $343.2
Price variance                                                          (40.4)          (1.8)         25.1       (17.1)
Volume variance                                                         110.8           22.0         121.3       254.1
Hedging gain variance                                                    15.1            -            44.1        59.2
-------------------------------------------------------------- -------------- -------------- ------------- -----------
2001 SALES REVENUES                                                    $234.5          $45.2        $359.7      $639.4
-------------------------------------------------------------- -------------- -------------- ------------- -----------
-------------------------------------------------------------- -------------- -------------- ------------- -----------
</TABLE>

ROYALTIES

Royalties increased by $51.7 million to $132.7 million for the year ended
December 31, 2001, as a consequence of the increase in production revenue. The
royalty rate before hedging for the year ended December 31, 2001, decreased to
22.5% from 23.0% for the year 2000. In the current commodity price environment,
Enerplus expects a royalty rate of approximately 21% for 2002, without taking
into account future acquisitions.

OPERATING EXPENSES

Operating expenses increased to $120.1 million for the year ended December 31,
2001 from $55.0 million in 2000, due mainly to the higher production volumes
associated with acquisition activities. This represents a cost of $6.09/BOE in
2001 compared to $4.83/BOE in 2000. Increased activity levels in the industry
during the first nine months of 2001 created a higher demand for goods and
services and placed a corresponding upward pressure on costs. In addition,
Enerplus experienced higher electricity costs in the first half of 2001 compared
to 2000. Finally, the acquisition of properties during 2000 and 2001 with
relatively higher operating costs than the pre-existing property portfolio added
to Enerplus' operating cost per BOE.

Lower electricity costs and reduced activity levels in the industry are expected
to stabilize and moderate Enerplus' operating expenses in 2002.


<PAGE>

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses were $13.0 million for the year ended
December 31, 2001 compared to $7.2 million for the year 2000. The increase
reflects the additional costs of managing entities acquired during 2000 for a
full year. General and administrative costs per BOE of production increased
marginally to $0.66/BOE for 2001 compared to $0.63/BOE for 2000.

In accordance with the full cost method of accounting, Enerplus capitalized $7.5
million of G&A costs in 2001 compared to $7.9 million capitalized in 2000. The
majority of these capitalized costs represent compensation costs for staff
involved in development drilling and acquisition activities.

In 2002 the Fund is targeting G&A costs of approximately $0.60/BOE, before
taking into account any further acquisitions.

MANAGEMENT FEES

Management services are supplied to Enerplus on a fee and cost reimbursement
basis. Management fees expensed were $9.3 million for the year ended December
31, 2001 represents an increase of $4.8 million over the year 2000 as a result
of higher operating income as well as the increase in the base management fee
percentage as discussed below relative to the restructuring of management fees
in their entirety.

In conjunction with the reverse takeover of Enerplus, a new management agreement
was approved by the Unitholders on June 21, 2001. Under the new agreement, base
management fees were set at 2.75% of operating income (compared to pre-June 21,
2001 rates of 2.2% for EnerMark and 3.5% for Enerplus). In addition, acquisition
and divestment fees (capitalized for financial statement purposes) were
eliminated and were replaced by performance fees based on both the total return
of the Fund, and its relative performance as compared to other senior
conventional oil and gas trusts. The performance fee can range between 0% and 4%
of operating income. In connection with the merger, the management company was
paid a fee of 172,500 Enerplus Trust Units with a value of $5 million in 2001,
which was capitalized as part of the merger cost. The management fee is
described in Note 6 to the financial statements.

In 2002, the base management fee will be 2.75% of the Fund's operating income.
In addition, there are two types of incremental performance fees which can range
in aggregate from 0% to 4%:

Total Return Performance Fee (minimum 0%, maximum 2% of the Fund's operating
income)

1.   If the total return of Enerplus Units (amount of distributions and
     appreciation in Trust Unit price) exceeds 11%, then the Total Return
     Performance Fee will be a minimum of 0.5%.

2.   If the total return of Enerplus Units is less than the yield on 10-year
     Government of Canada bonds plus 5%; then the Total Return Performance Fee
     will be 0% (subject to the minimum payment described in (1) above).

3.   If the total return of Enerplus Units exceeds the yield on 10-year
     Government of Canada bonds plus 15%; then the Total Return Performance Fee
     will be 2% of the operating income of the Fund.

4.   If the total return of Enerplus Units is between the yield on 10-year
     Government of Canada bonds plus a factor of 5% to 15% (subject to the
     minimum payment described in (1) above), then a sliding scale calculation
     (ranging from 0% to 2%) will be used.

Relative Performance Fee (minimum 0%, maximum 2% of the Fund's operating income)

1.   The relative performance of Enerplus as compared to seven other qualifying
     conventional oil and gas trusts will be ranked based on distributions and
     unit price appreciation.

2.   The Relative Performance Fee will be calculated using a percentage equal to
     2% divided by the number of trusts in the top half of the rankings
     multiplied by the number of rankings which Enerplus is below the number one
     ranking and subtracting the product obtained thereby from 2%; and

3.   If the resulting value obtained is less than zero, then no Relative
     Performance Fee will be paid, otherwise the Relative Performance Fee will
     be the amount obtained by multiplying the resulting percentage (not to
     exceed 2%) by the operating income of the Fund.

<PAGE>

In effect, Enerplus must rank at least fourth out of the eight largest
conventional oil and gas trusts (including Enerplus) before any Relative
Performance Fee is payable.

This fee arrangement will be reviewed annually with the Board of Directors. The
new management fee arrangements were designed to better align the interests of
the Manager with the interests of Unitholders.

INTEREST EXPENSE

Interest expense for the year 2001 was $17.6 million, up $2.3 million from 2000
due to higher outstanding bank debt incurred in connection with the acquisition
activities in 2000 and 2001. Bank debt increased to $412.6 million at December
31, 2001 from $275.9 million on December 31, 2000.

During 2001, Enerplus' interest costs were entirely based on floating rates, as
those rates offered the most cost-effective financing strategy. Subsequent to
the year end, Enerplus entered into an interest rate swap that fixed the rate on
a notional $25 million in debt for a three year term from January 18, 2002 to
January 18, 2005 at a rate of 3.89% per annum (before banking fees that are
expected to range between 0.85% and 1.05%). Enerplus may consider fixing an
additional portion of its interest rate exposure in 2002, depending on its
financing requirements and the forward interest rate market.

DEPLETION AND CEILING TEST

Depletion of the property, plant and equipment is provided on the
unit-of-production method based on constant price proven reserves. An estimate
of the future costs for restoration and abandonment of well sites and facilities
is updated annually and this cost estimate is amortized over the life of the
properties on a unit-of-production basis.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------- ------------- ------------
                                                                                                     2001         2000
------------------------------------------------------------------------------------------- ------------- ------------
<S>                                                                                                <C>           <C>
Depletion and depreciation                                                                         $181.1        $76.5
Amortization of future site restoration                                                               5.9          3.8
Amortization of deferred hedging costs                                                                7.1            -
                                                                                            ------------- ------------
Total                                                                                              $194.1        $80.3
------------------------------------------------------------------------------------------- ------------- ------------
------------------------------------------------------------------------------------------- ------------- ------------
</TABLE>

Depletion, depreciation and amortization increased to $194.1 million in 2001
from $80.3 million in 2000. Included in the amortization amount are $7.1 million
of amortized costs relating to the mark-to-market value of the Enerplus
commodity price forward contracts at the time of the reverse takeover. The
mark-to-market value of these contracts was recognized as either a deferred
hedge asset or liability as part of the acquisition cost and will be amortized
over the remaining term of the contract ending in 2004. The actual gain (or
loss) associated with this contract will be recognized in oil and gas sales as
they are realized.

The rate of depletion and depreciation has increased to $9.18/BOE in 2001 from
$6.72/BOE in 2000. The increase is the result of higher costs attributed to
petroleum and natural gas assets acquired during 2000 and 2001. The adoption of
the liability method of accounting for future income taxes, as required by
Canadian generally accepted accounting principles, had the effect of
substantially increasing the recorded value of acquired property, plant and
equipment compared to the previous deferral method of accounting. In the case of
the corporate acquisitions in 2000 the value of acquired assets were increased
to reflect any shortfall between the net book value and the cost basis for
income tax purposes.

Enerplus places a limit on the carrying value of property, plant and equipment
(the "ceiling test"). The cost of these assets, less accumulated depletion, is
limited to the estimated future net revenue from proved reserves (based on
unescalated prices and costs at the balance sheet date) less estimated future
general and administrative costs, financing costs, and management fees. There
was a surplus in the ceiling test at year end 2001.

TAXES

Capital taxes increased to $4.7 million for the year 2001 from $2.9 million in
2000 primarily due to the increase in capital structure.

For the year ended December 31, 2001, a future income tax recovery of $31.5
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.


<PAGE>

However, the Fund's operating companies are required to account for future
income taxes. Future income taxes arise because of the difference between the
accounting and tax bases of the operating companies' assets and liabilities.

NETBACKS

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------- ----------- -----------
Netbacks per BOE of Production (6:1) year ended December 31,                                       2001        2000
------------------------------------------------------------------------------------------- ----------- -----------
<S>                                                                                              <C>         <C>
Oil and gas sales                                                                                $32.43      $30.14
Royalties                                                                                         (6.73)      (7.10)
Operating expenses                                                                                (6.09)      (4.83)
General and administrative expenses                                                               (0.66)      (0.63)
Management fees                                                                                   (0.47)      (0.40)
Interest expense, net of interest and other income                                                (0.85)      (1.30)
Capital taxes                                                                                     (0.24)      (0.26)
Restoration and abandonment cash costs                                                            (0.13)      (0.13)
                                                                                            ----------- -----------
         Funds flow from operations                                                               17.26       15.49
Depletion and depreciation                                                                        (9.18)      (6.72)
Amortization, net of cash costs                                                                   (0.54)      (0.21)
Future income tax recovery (provision)                                                             1.60       (1.35)
                                                                                            ----------- -----------
         Net income per BOE of production                                                        $ 9.14      $ 7.21
------------------------------------------------------------------------------------------- ----------- -----------
</TABLE>

NET INCOME AND FUNDS FLOW FROM OPERATIONS

Net income for the year ended December 31, 2001 was $180.3 million, or $3.28 per
Trust Unit, up 119% (7% per Trust Unit) from $82.2 million or $3.06 per Trust
Unit for the year 2000. After adding back non-cash expenses such as depletion,
depreciation, amortization and the future income tax provision (recovery), the
resultant Funds Flow from Operations was $340.2 million in 2001 or $6.20 per
Trust Unit compared to $176.4 million or $6.57 per Trust Unit in 2000.

QUARTERLY FINANCIAL INFORMATION

<TABLE>
<CAPTION>
--------------------------------------------------------------- ------------- ------------ ---------------------------
                                                                  Oil and Gas                      Net income per Unit
                                                                  Revenue Net          Net ---------------------------
$ millions, except per Unit amounts                              of Royalties       Income         Basic       Diluted
--------------------------------------------------------------- ------------- ------------ ------------- -------------
<S>                                                              <C>                <C>            <C>         <C>
2001
First quarter                                                          $136.7       $ 59.7         $1.42         $1.41
Second quarter                                                          109.3         58.5          1.30          1.29
Third quarter                                                           130.9         25.1          0.39          0.39
Fourth quarter                                                          129.8         37.0          0.55          0.55
                                                                ------------- ------------
TOTAL                                                                  $506.7       $180.3         $3.28         $3.28
--------------------------------------------------------------- ------------- ------------ ------------- -------------
--------------------------------------------------------------- ------------- ------------ ------------- -------------
2000
First quarter                                                          $ 43.5       $ 10.1         $0.45         $0.45
Second quarter                                                           55.4         10.9          0.42          0.42
Third quarter                                                            68.6         23.9          0.88          0.88
</TABLE>


<TABLE>
<S>                                                              <C>                <C>            <C>         <C>
Fourth quarter                                                           94.7         37.3          1.16          1.16
                                                                ------------- ------------
TOTAL                                                                  $262.2       $ 82.2         $3.06         $3.05
--------------------------------------------------------------- ------------- ------------ ------------- -------------
--------------------------------------------------------------- ------------- ------------ ------------- -------------
</TABLE>

<PAGE>

CASH AVAILABLE FOR DISTRIBUTION

Enerplus distributes the net cash flow from its oil and gas properties to the
Trust Unitholders on a monthly basis. A portion of this cash flow is typically
withheld to repay bank debt incurred with respect to acquisitions and capital
spending. For the year ended December 31, 2001, Enerplus generated $340.2
million in Funds Flow from Operations. Of this amount (together with certain
funds described in the following table), $316.5 million was paid to Unitholders
and $48.8 million was retained for debt reduction.

Management monitors the Fund's distribution payout policy with respect to
forecast cash flows, debt levels, and spending plans. The level of cash retained
for debt repayment typically varies between 5% and 10% of total cash flow,
although 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.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------- -------------- -------------
Reconciliation of Cash Available for Distribution for the year ended December 31,
$ millions, except per Unit amounts                                                                 2001          2000
----------------------------------------------------------------------------------------- -------------- -------------
<S>                                                                                               <C>           <C>
Funds flow from operations                                                                        $340.2        $176.4
Site restoration and abandonment costs incurred                                                      2.6           1.4
Cash withheld for debt reduction                                                                   (48.8)        (11.7)
Enerplus cash flows (Note A)                                                                        16.9             -
Accruals (Note B)                                                                                    5.6             -
Pursuit cash flows, net of debt reduction (Note C)                                                    -            2.1
                                                                                          -------------- -------------
Cash available for distribution (Note D)                                                          $316.5        $168.2
                                                                                          -------------- -------------
Cash available for distribution per Trust Unit                                                    $ 5.67        $ 5.49
----------------------------------------------------------------------------------------- -------------- -------------
</TABLE>

Cash available for distribution per Trust Unit of $5.67 for 2001 represent what
an EnerMark Unitholder would have received for the 2001 production year (which
was paid to Unitholders from March 20, 2001 to February 20, 2002) after
converting 1 EnerMark Unit for 0.173 Enerplus Unit pursuant to the terms of the
Merger. Similarly, cash available for distribution of $5.49 per Trust Unit for
the 2000 production year was paid to EnerMark Unitholders between March 20, 2000
and February 20, 2001.

Note A:   As a result of the reverse takeover, funds flow from operations do
          not include funds earned by the former Enerplus prior to June 21,
          2001. However, cash distributions include the July/August payment in
          respect of this cash flow. As a result, the July/August payment to
          Unitholders is added to funds flow from operations for purposes of
          this reconciliation.

Note B:   According to the current 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 year are
          added back to funds flow from operations for purposes of this
          reconciliation.

Note C:   In the acquisition of Pursuit Resources Corp., Enerplus distributed
          a portion of the Pursuit net cash flow generated between the effective
          date and the closing date of the acquisition.

Note D:   The cash for distribution of $316.5 million in 2001 can be reconciled
          to the cash paid to Unitholders of $328.9 million on the Statement of
          Cash Flows by subtracting the January and February 2001 payments to
          Unitholders and adding the January and February 2002 payments to
          Unitholders, as the Statement of Cash Flows reflects cash payments to
          Unitholders during the calendar year.


<PAGE>

CAPITAL EXPENDITURES

During the year ended December 31, 2001, Enerplus spent $152.2 million (2000 -
$65.8 million) on capital expenditures and acquisitions net of divestitures.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- ----------- -----------
Capital Expenditures for the year ended December 31, $ millions                                     2001        2000
-------------------------------------------------------------------------------------------- ----------- -----------
<S>                                                                                               <C>          <C>
Development drilling and completions                                                              $ 83.0      $ 27.1
Plant and facilities                                                                                53.6        11.9
Office and other expenditures                                                                        6.7         1.0
                                                                                             ----------- -----------
       Total                                                                                       143.3        40.0
Acquisitions of oil and gas properties                                                              77.4        51.1
Dispositions of oil and gas properties                                                             (68.5)      (25.3)
                                                                                             ----------- -----------
       Total Net Capital Expenditures                                                             $152.2      $ 65.8
-------------------------------------------------------------------------------------------- ----------- -----------
-------------------------------------------------------------------------------------------- ----------- -----------

Enerplus finances its capital expenditures through bank borrowing, new equity issues, and by withholding a portion
of funds flow from operations. The following table outlines the development spending by major property:

</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------- -------------------------------------------------------- --------------
                                                                         2001                                     2000
                                               -------------------------------------------------------- --------------
Capital Expenditures for the year                Development
($ millions) ended December 31,                     Drilling     Facilities         Other         Total          Total
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
<S>                                              <C>             <C>                <C>          <C>             <C>
Hanna/Garden Plains                                    $11.5          $11.9          $1.7        $ 25.1          $ 3.5
Pembina Five Way                                         7.2            1.7             -           8.9              -
Medicine Hat                                             6.7            5.8             -          12.5            0.5
Bantry                                                   7.7            2.3             -          10.0            1.9
Benjamin                                                 2.4            3.2           0.1           5.7            1.4
Giltedge                                                 0.4            3.8             -           4.2            9.7
Other                                                   47.1           24.9           4.9          76.9           23.0
                                               ------------- -------------- ------------- ------------- --------------
Total                                                  $83.0          $53.6          $6.7        $143.3          $40.0
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
</TABLE>

Enerplus is currently forecasting capital expenditures of approximately $130
million in 2002 on existing properties. Of this total, Enerplus expects to spend
$20 million at Joarcam drilling 18 potential oil wells and 5 potential gas
wells, recompleting 30 wells, and increasing the facility infrastructure
capacity in the region. At Hanna/Garden Plains, Enerplus expects to spend $12
million drilling 75 shallow gas wells, performing well workovers and completing
facility modifications. At Medicine Hat North, the capital budget of $9 million
includes drilling 50 potential gas wells and installation of compression in the
region. At Bantry, Enerplus expects to spend $5 million drilling 37 potential
gas wells and refracing existing wells.

Enerplus routinely evaluates its property portfolio and disposes of properties
that are viewed as non-core holdings with limited contribution to cash flow or
upside development potential. In 2001, Enerplus sold $68.5 million worth of
non-core oil and gas properties. Offsetting these dispositions were $77.4
million of acquisitions for the year, including $25.0 million on Kaybob, $8.8
million on Ferrier, and $8.3 million on Gleneath. Enerplus expects to continue
its process of rationalizing marginal properties and acquiring new properties in
2002.

LIQUIDITY AND CAPITAL RESOURCES

Enerplus' bank debt increased to $412.6 million as at December 31, 2001 compared
to $275.9 million at December 31, 2000.


<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------- ----------- ------------
Continuity of Bank Debt ($ millions)                                                                 2001         2000
--------------------------------------------------------------------------------------------- ----------- ------------
<S>                                                                                                <C>          <C>
Beginning balance January 1,                                                                       $275.9       $131.3
Items that affect bank debt as per Statement of Cash Flows
Purchase of property, plant and equipment                                                           243.0        251.9
Proceeds on sale of property, plant and equipment                                                   (75.3)       (18.5)
Assumption of acquired entities' bank debt                                                           78.6         66.9
Proceeds from issue of Trust Units                                                                 (151.4)      (120.6)
Cash distributions paid to Unitholders during the calendar year                                     328.9        132.6
Funds flow from operating activities (on an accrued basis)                                         (340.2)      (176.4)
Increase in non-cash operating working capital                                                       52.9         11.4
Other                                                                                                 0.2         (2.7)
                                                                                              ----------- ------------
Ending Bank Debt December 31,                                                                      $412.6       $275.9
                                                                                              ----------- ------------
Bank Debt per Trust Unit at December 31,                                                           $ 5.93       $ 6.74
--------------------------------------------------------------------------------------------- ----------- ------------
</TABLE>

As at March 1, 2002, Enerplus renegotiated its bank facilities and consolidated
the bank lines of the former EnerMark and Enerplus operating companies. Enerplus
currently has $620 million committed under the unsecured bank facilities with a
syndicate of 7 banks, comprised of a $590 million revolving 364 day committed
facility with an incremental amortizing two-year term, and an additional $30
million demand operating facility. These credit facilities have no financial
covenants, however, the size of the facility is based on the banks' evaluation
of the value of Enerplus' proven oil and gas reserves. The banks have reserved
the right to revise the commitment based on a review of the year end reserve
information. The bank debt has priority over claims of and distributions to the
Unitholders. However, Unitholders have no direct liability with respect to the
bank loan should revenues be insufficient to repay it.

In the event that the revolving bank line is not extended at the end of the 364
day revolving period, no payments are required to be made to non-extending
lenders during the first year of the term period. However, Enerplus will be
required to maintain certain minimum balances on deposit with the syndicate
agent.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- ------------ ------------
Financial Leverage and Coverage                                                                      2001         2000
-------------------------------------------------------------------------------------------- ------------ ------------
<S>                                                                                                 <C>          <C>
Bank debt to funds flow from operations                                                              1.2x         1.6x
Funds flow from operations to interest expense                                                      19.3x        11.5x
Bank debt to bank debt plus equity                                                                    23%          27%
-------------------------------------------------------------------------------------------- ------------ ------------
</TABLE>

Enerplus has no off-balance sheet financing arrangements.

In 2002, Enerplus may consider replacing a portion of its bank debt with term
debt (such as 5-10 year debentures) in order to diversify credit sources, secure
term financing commitments, and potentially fix interest rates for a longer
term.

NATURAL GAS PIPELINE COMMITMENTS

Enerplus has contracted to transport 10MMcf/day of natural gas into Chicago on
the Foothills and Northern Border pipelines until October 31, 2008. It has also
agreed to transport 5 MMcf/day to Marshfield, Illinois on the TransCanada and
Viking pipelines until October 31, 2008. In addition, Enerplus has pipeline
commitments to transport 5 MMcf/day into Chicago on Alliance Pipeline until
October 31, 2015.


<PAGE>

TRUST UNIT INFORMATION

Enerplus had 69,532,000 Trust Units and no warrants outstanding at December 31,
2001 compared to 40,925,000 Trust Units and 3,045,000 warrants at December 31,
2000. The weighted number of Trust Units outstanding during 2001 was 54,907,000
(2000 - 26,841,000).

During 2001, Enerplus issued 20,863,000 additional Trust Units pursuant to the
Merger agreement on June 21, 2001. In addition, 1,267,000 Trust Units were
issued to acquire the non-controlling interest with respect to the Cabre
acquisition, and 4,312,500 Trust Units were issued pursuant to the November 15,
2001 equity offering. Enerplus also issued 3,045,000 warrants on December 31,
2000 and an additional 390,000 warrants on January 8, 2001 pursuant to the Cabre
acquisition, of which 1,197,000 were exercised during 2001 and 2,238,000 expired
on December 17, 2001.

INCOME TAXES

The following sets out a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus Trust Units as capital property. The summary is
not exhaustive in nature and is not intended to provide legal or tax advice.
Unitholders or potential Unitholders should consult their own legal or tax
advisors as to their particular tax consequences.

CANADIAN TAXPAYERS

The Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and,
accordingly, Trust Units of the Fund are qualified investments for RRSPs, RRIFs,
RESPs, and DPSPs. Each year, the Fund is required to file an income tax return
and any taxable income in the Fund is allocated to the Unitholders.

Unitholders are required to include in computing income their pro-rata share of
any taxable income earned by the Fund in that year. An investor's adjusted cost
base ("ACB") in a Trust Unit equals the purchase price of the Unit less any
non-taxable cash distributions received from the date of acquisition. To the
extent a Unitholder's ACB is reduced below zero, such amount will be deemed to
be a capital gain to the Unitholder and the Unitholder's ACB will be brought to
$nil.

Enerplus paid $6.25 per Trust Unit in cash distributions to Unitholders during
the 2001 calendar year. For Canadian tax purposes, 25% of these distributions,
or $1.54 per Unit was a tax deferred return of capital, 74% or $4.6269 per Unit
was taxable to Unitholders as other income, and 1% or $0.0831 per Unit was
taxable dividend income.

U.S. TAXPAYERS

U.S. Unitholders who receive cash distributions are subject to a 15% Canadian
withholding tax, applied to the taxable portion of the distribution as computed
under Canadian tax law. U.S. taxpayers may be eligible for a foreign tax credit
with respect to Canadian withholding taxes paid.

The taxable portion of the cash distribution for U.S. tax purposes is determined
by Enerplus in relation to its current and accumulated earnings and profits
using U.S. income tax principles. The taxable portion so determined is
considered to be a dividend for U.S. tax purposes.

The non-taxable portion of the cash distribution, is a return of the cost (or
other basis). The cost (or other basis) is reduced by this amount for computing
any gain or loss arising from disposition. However, if the full amount of the
cost (or other basis) has been recovered, any further non-taxable distributions
should be reported as gains.

Enerplus paid US$3.83 per Trust Unit to U.S. residents during the 2001 calendar
year, of which 13% or US$0.49 per Unit was a tax deferred return of capital and
87% or US$3.34 per Unit was a taxable dividend.

BUSINESS RISKS

Investors that purchase Enerplus Trust Units are participating in the net cash
flow from a portfolio of western Canadian crude oil and natural gas producing
properties. As such, the cash flow paid to investors and the value of Enerplus
Units are subject to numerous risk factors. These risk factors, many of which
are associated with the oil and gas industry, include, but are not limited to
the following influences:


<PAGE>

o    The prices that Enerplus receives for its crude oil, natural gas, and NGLs
     can fluctuate significantly due to global and North American supply and
     demand, worldwide economic conditions, weather, political stability,
     Canada/U.S. exchange rates, the proximity to and capacity of transportation
     and processing facilities, the price and availability of alternative fuels
     and government regulations. Declines in oil or natural gas prices will have
     an adverse effect on our operations, financial condition, reserves and
     ultimately our ability to pay distributions to Trust Unitholders.

o    Oil and natural gas reserves naturally deplete as they are produced over
     time. Enerplus' ability to replace production depends on its success in
     acquiring new reserves and developing existing reserves. Since Enerplus
     distributes the majority of its net cash flow to Unitholders, it must
     finance a large portion of this acquisition and development activity
     through continued access to the equity and debt capital markets. As such,
     it is dependent on continued access to the capital markets to maintain and
     grow value for Unitholders.

o    Acquisition of oil and gas assets depend on Enerplus' assessment of value
     at the time of acquisition. Incorrect assessments of value can adversely
     affect distributions to Unitholders and the value of the Trust Units.

o    The value of Enerplus Trust Units is based on the underlying value of the
     oil and gas reserves. Geological and operational risks can affect the
     quantity and quality of reserves and the cost of ultimately recovering
     those reserves. Lower oil and natural gas prices increase the risk of
     write-downs of Enerplus' oil and gas property investments.

o    Changing interest rates can affect borrowing costs and the market price of
     yield-based investments such as Enerplus.

o    Government royalties, income tax laws, environmental laws and regulatory
     requirements can have a significant financial and operational impact on
     Enerplus.

o    Operating costs may be difficult to control as increased activity in the
     oil and gas industry may increase the cost of goods and services and make
     it difficult to hire and retain staff.

o    Third party operators operate approximately 35% of Enerplus' production,
     which reduces Enerplus' ability to control costs, capital, and operation
     activities with respect to these properties.

o    Enerplus assumes customer credit risk associated with oil and gas sales,
     financial hedging transactions, and joint venture participants.

o    Environmental and safety risks influence the workforce, operating costs,
     and compliance with regulatory standards.

Enerplus has no control over many of these risk factors. Nevertheless,
management has attempted to mitigate some of these risks through the following:

o    Enerplus has an ongoing commodity price risk management strategy that is
     intended to provide price protection on a portion of its future production
     in the event of adverse commodity price movement, while retaining exposure
     to upside price movements.

o    Enerplus has listings on the Toronto and New York Stock exchanges and
     maintains an active investor relations program designed to facilitate
     access to equity capital markets.

o    Enerplus maintains a prudent capital structure by retaining a portion of
     the cash flow for debt repayment, rationalizing properties that no longer
     meet portfolio guidelines, managing capital expenditures within rate of
     return guidelines, and utilizing the equity markets when appropriate.

o    Acquisitions are subject to stringent investment criteria, due diligence,
     and review and approval by the Fund's Board of Directors. Independent
     reservoir engineers evaluations are required for acquisitions in excess of
     $5 million.

o    Enerplus strives to acquire low risk, mature properties with a high
     proportion of proven reserves, high cash netbacks, long reserve lives, and
     predictable production.

o    Similarly, Enerplus participates in lower-risk development projects, while
     farming out or monetizing higher risk exploratory prospects.

<PAGE>

o    Each year a significant portion of Enerplus' proven and probable oil and
     gas reserves are evaluated by a firm of independent reservoir engineers.
     Approximately 83% of the net present value of the total established
     reserves discounted at 12% were evaluated at December 31, 2001. A special
     committee of the Board of Directors reviews and approves the reserve
     report.

o    Enerplus monitors the interest rate forward market and has recently begun
     to fix the interest rate on a portion of its debt through interest rate
     swaps for terms up to 3 years. In addition, the Fund may consider fixing
     longer-term interest rates in conjunction with the issuance of longer-term
     debentures.

o    Management has established credit policies and controls designed to limit
     the risk of default or nonpayment with respect to oil and gas sales,
     financial hedging transactions, and joint venture participants.

o    Enerplus offers competitive incentive-based compensation packages to
     attract and retain qualified staff.

o    Enerplus has employee training and safety programs designed to educate on
     safety awareness, monitor incidents and prevent accidents.

o    Enerplus has a site inspections program and a corrosion risk management
     program designed to ensure compliance with environmental laws and
     regulations.

o    Enerplus maintains certain insurance coverages related to liability and
     property exposures.

BUSINESS PROSPECTS

Enerplus strives to be the premier oil and gas income fund in North America by
continuing to deliver top quartile returns to its Unitholders. The Fund's
objective is to increase value for Unitholders through successful acquisitions
and the low-risk development of its existing properties utilizing technology,
creativity and innovation.

Enerplus offers investors the benefits of owning a diversified portfolio of
mature crude oil and natural gas producing properties and related facilities. As
such, the most influential factor affecting the future prospects of the Fund is
the price of crude oil and natural gas. Commodity prices continue to be volatile
and difficult to forecast.

Natural gas prices are expected to remain weak for the first part of 2002, or
until such time as economic and weather-related demand can reduce the current
North American storage oversupply. Over the longer term, Enerplus expects
natural gas prices to strengthen, although not to the elevated levels
experienced in the first quarter of 2001. A cyclical re-balancing of gas supply
is expected as reduced exploration and development drilling, combined with
natural reservoir depletion, reduces supplies at the same time North American
demand is recovering.

The price of crude oil has weakened since the third quarter of 2001 due to
reduced economic demand and the threat that OPEC may abandon its production
quota practices in an attempt to regain market share from non-OPEC nations.
Other developments, such as continued political instability in the Middle East,
natural reservoir declines, reduced exploration and development drilling, and
signs of a worldwide economic recovery are creating compensating upward pressure
on oil prices.

Enerplus has a price risk management strategy that is designed to provide a
measure of price protection in the event of adverse commodity price movement,
while retaining exposure to upside price movements. At year end, approximately
28% of Enerplus' expected natural gas production and 15% of its expected crude
oil production was protected against downward price movement. Even with these
positions, the Fund's cash flow remains sensitive to changes in commodity prices
as demonstrated by the following table:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- -------------------------
                                                                                                        Effect on 2002
                                                                                                     Distributions per
Sensitivity to Changes in Price and Exchange Rate                                                           Trust Unit
-------------------------------------------------------------------------------------------- -------------------------
<S>                                                                                                  <C>
Change of CDN$0.10 per Mcf in the price of natural gas                                                           $0.07
Change of US$1.00 per barrel in the price of WTI crude oil                                                       $0.15
Change of 1,000 BOE/day in production                                                                            $0.06
Change of $0.01 in the US$/CDN$ exchange rate                                                                    $0.04
Change of 1% in interest rate                                                                                    $0.05
-------------------------------------------------------------------------------------------- -------------------------
</TABLE>


<PAGE>


As with most yield-based investments, the level of interest rates can have an
impact on the trading value of Enerplus Trust Units. The recent period of
declining interest rates has had a positive impact on Enerplus' Trust Unit value
and the Fund's ability to raise capital. While the prospect of an economic
recovery may reverse the current trend of low interest rates, such a recovery
would be positive for the oil and natural gas markets, and it is expected that
the benefits associated with a commodity price recovery far outweighs the risk
of rising short-term interest rates.

The combination of Enerplus and EnerMark has created the largest conventional
oil and gas income fund in North America. It has increased liquidity for
investors and attracted a broader base of institutional and U.S. investors
through its listings on the TSE and NYSE. More importantly, it has improved the
Fund's access to capital and its ability to pursue large acquisition
opportunities.

Enerplus also has numerous internal development opportunities on existing
properties, including low risk development drilling, the application of
waterflood technology, and application of incremental recovery techniques
designed to increase production and improve reservoir recoveries. In particular,
Enerplus has a large inventory of low-cost shallow gas drilling opportunities
that can be activated quickly in the event of a recovery in natural gas prices.

As Enerplus distributes much of its net cash flow, its ability to replace
production and grow Unitholder value depends on its success in acquiring new
reserves. Although Enerplus bid on numerous asset and corporate packages
throughout 2001, the Fund was largely unsuccessful due to its disciplined
acquisition criteria. With the recent decline in commodity prices, the desire or
need of many E&P companies to strengthen their balance sheets, and the asset
rationalization that typically follows a period of industry consolidation, we
expect that 2002 will bring better opportunities to acquire quality properties
at more reasonable prices.

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.