**EXHIBIT
99.3**
 
 **MANAGEMENT’S
DISCUSSION AND ANALYSIS (“MD&A”)**
  The
following discussion and analysis of financial results is dated February 24,
2005 and is to be read in conjunction with the audited consolidated financial
statements as at and for the years ended December 31, 2004 and 2003. All amounts
are stated in Canadian dollars unless otherwise specified. All note references
relate to the notes included with the consolidated financial statements. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Where applicable, natural gas has been
converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. The BOE
rate is based on an energy equivalent conversion method primarily applicable at
the burner tip and does not represent a value equivalent at the wellhead. Use of
BOE in isolation may be misleading.
 
 Throughout
the MD&A, we use the terms funds flow from operations (“funds flow”) and
cash available for distribution. These terms as presented do not have any
standardized meaning as prescribed by Canadian generally accepted accounting
principles (“GAAP”), and therefore they may not be comparable with the
calculation of similar measures for other entities. Funds flow as presented is
not intended to represent operating cash flows or operating profits for the
period nor should it be viewed as an alternative to cash flow from operating
activities, net earnings or other measures of financial performance calculated
in accordance with GAAP. Funds flow is used by management to analyze operating
performance, leverage and liquidity. All references to funds flow throughout
this report are based on cash flow from operating activities before changes in
non-cash working capital. Cash available for distribution is calculated using
funds flow less cash withheld for acquisitions and capital expenditures.
 
 **2004** **Overview**
  We
started 2004 with the acquisition of Ice Energy Limited (“Ice Energy”) for
$130.5 million in January which secured development opportunities in
Saskatchewan and Alberta shallow gas areas. In June, we completed the single
largest acquisition in our 19-year history with the acquisition of certain
properties from ChevronTexaco Corporation (“ChevronTexaco”) for $467.2 million.
This acquisition added additional shallow gas and crude oil waterflood
opportunities to our asset base. Against this backdrop of acquisition activity,
we posted a record year for capital expenditures on our existing properties
spending $206.8 million on development projects and drilling 367 net wells with
a success rate of 99%.
  Production
increased 8% year-over-year, reflecting the partial-year impact of the
acquisitions and the results of our capital program. Our average selling price
per BOE also increased 11% in 2004 on the strength of higher crude oil prices
and slightly higher natural gas prices. The combination of higher production and
higher prices helped fuel an increase in revenues. In addition, we experienced
an increase in operating costs and general and administrative costs as a result
of the higher activity levels and corresponding competitive pressures within the
industry for services as well as higher performance based compensation costs.
For 2004, our funds flow from operations increased to $540.0 million from $413.2
million in 2003. Our payout ratio decreased to 79% as we held distributions per
trust unit constant throughout 2004 and chose to reinvest the additional funds
flow into acquisitions and capital development opportunities.
 
 **Highlights**
  •
    Our
      Canadian unitholders realized a 21.5% total return in 2004 (representing
      the appreciation in unit price plus distributions paid during the year).
      This performance placed Enerplus first on a three-year rolling basis for
      the third year in a row in a peer group of the eight largest conventional
      oil and gas trusts.•
    Our
      U.S. unitholders realized a 29.9% total return in 2004, as the
      appreciation in the Canadian dollar effectively increased distributions
      and the unit price when exchanged into U.S. dollars.•
    Funds
      flow from operations, driven by strong oil and natural gas prices and
      higher production, increased 31% to $540.0 million and 14% per trust unit
      to $5.44 per trust unit.•
    We
      paid $426.7 million to unitholders ($4.20 per trust unit) and retained
      $113.3 million ($1.11 per trust unit) for capital development
      opportunities. This represented a payout ratio of
79%.
 **ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **47**









•
    Our average
      annual production volumes of 75,130 BOE/day exceeded our production target
      for 2004 of 74,000 BOE/day, and set a new record of annual production for
      the Fund.•
    On January 7,
      2004 we closed the acquisition of Ice Energy for total consideration of
      $130.5 million.•
    On June 30,
      2004 we completed the acquisition of properties from ChevronTexaco for
      total consideration of $467.2 million, which added 33.4 million BOE of
      proved plus probable reserves and approximately 11,500 BOE/day of
      production.•
    In connection
      with the ChevronTexaco acquisition we completed an equity offering,
      issuing 8.8 million trust units for gross proceeds of $301.8 million
      ($286.2 million net of costs).•
    Net
      income was slightly higher than the prior year, however on a trust unit
      basis it decreased 10% as a result of our equity issue that increased the
      number of units outstanding.•
    Enerplus
      continued its active development program, investing $206.8 million in
      development drilling and facility enhancements. In 2004 we participated in
      367 net wells with a 99% success rate.•
    Proved
      reserves increased 12% to 279.1 MMBOE and proved plus probable reserves
      increased 24% to 406.2 MMBOE supported by the addition of 47.7 MMBOE of
      probable reserves from our Joslyn lease. Positive reserve additions from
      acquisition and development efforts were successful in replacing 209% of
      2004 production on a proved basis, and 384% on a proved plus probable
      basis.•
    The Fund’s
      finding, development and acquisition costs (“FD&A”) for the
      year were $11.34 per BOE on a proved plus probable basis and $15.83 per
      BOE on a proved basis including future development
  capital.•
    Enerplus’
      Reserve Life Index (“RLI”) continued to be one of the longest in the
      sector at 14.0 years on a proved plus probable basis and 10.1 years on a
      proved basis.•
    Our recycle
      ratio (operating income divided by FD&A) was 1.9x for 2004 and 1.8x on
      a three-year basis using proved plus probable reserves.•
    Operating
      costs increased 6% in 2004 to $7.14/BOE as a result of increased costs for
      labour, utilities and supplies along with an overall increase due to
      activity levels within the oil and gas industry.•
    General
      and administrative (“G&A”) expenses increased to $1.23/BOE as a result
      of increased cost pressures associated with retaining skilled staff,
      increased performance based compensation and increased compliance
      requirements.•
    Our
      commodity price risk management costs were $96.2 million ($3.50/BOE)
      during 2004 primarily due to record high crude oil prices that exceeded
      the call levels on our derivative instruments.•
    We
      negotiated a new $850 million unsecured, covenant-based, three-year
      committed bank credit facility.•
    We continue
      to maintain a conservative balance sheet as evidenced by a net debt to
      trailing funds flow ratio of 1.1x.
 ****
 **Results
of Operations**
 **Production**
 
 Daily production
during 2004 averaged 75,130 BOE/day, an 8% increase over average production
volumes of 69,414 BOE/day for 2003. This increase was primarily due to the
acquisitions of Ice Energy, which closed January 7, 2004 and ChevronTexaco,
which closed June 30, 2004.
 
 Our average
production during 2004 was weighted 60% natural gas and 40% liquids on a BOE
basis. Furthermore, production was widely distributed across more than 300
producing areas in Alberta, Saskatchewan, British Columbia and Manitoba. No
single area accounted for more than 7% of total production. With this diverse
production base there is less risk that operational problems with a single
property will have a material impact on our production and funds flow.
 
 Average production
volumes for the years ended December 31, 2004 and 2003 are outlined on the next
page:
 
 **ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **48**





Daily
      Production Volumes
    
    **2004**
    
    2003
    
    %
      ChangeNatural
      gas (Mcf/day)
    
    
    **271,091**
    
    
    240,907
    
    
    13
    %Crude
      oil (bbls/day)
    
    
    **25,550**
    
    
    24,597
    
    
    4
    %Natural
      gas liquids (bbls/day)
    
    
    **4,398**
    
    
    4,666
    
    
    (6
    %)Total
      daily sales (BOE/day)
    
    
    **75,130**
    
    
    69,414
    
    
    8
    %


Enerplus’ exit
production for the month of December 2004 averaged approximately 80,000 BOE/day.
We expect production for 2005 will average 75,500 BOE/day. This estimate takes
into account natural reservoir declines and forecast development expenditures of
$275 million. The estimate is before the effects of any future acquisitions,
however, it assumes we will dispose of non-core properties throughout the first
quarter of 2005 for proceeds of approximately $60 million. These non-core
properties are currently producing approximately 2,500 BOE/day.




Similar to our
experience in 2004, we expect a greater portion of our 2005 capital program to
be implemented in the latter part of the year, helping to increase our forecast
exit production to approximately 77,500 BOE/day without consideration of any
acquisitions or further divestments.




**Pricing**




Our earnings, funds
flow and financial condition are dependent on the prices received for our
natural gas and crude oil production. Natural gas and crude oil prices have
fluctuated widely during recent years.




The following table
compares the Fund’s average selling prices for 2004 with those of 2003. It also
compares the benchmark price indices for the same periods.





Average
      Selling Price(1)
    
    
    **2004**
    
    
    2003
    
    
    %
      ChangeNatural
      gas (per Mcf)
    
    **$**
    **6.56**
    
    $
    6.30
    
    
    4
    %Crude
      oil (per bbl)
    
    
    **43.80**
    
    
    36.15
    
    
    21
    %Natural
      gas liquids (per bbl)
    
    
    **38.14**
    
    
    33.43
    
    
    14
    %Per
      BOE
    
    **$**
    **40.90**
    
    $
    36.94
    
    
    11
    %




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




Average
      Benchmark Pricing
    
    
    **2004**
    
    
    2003
    
    
    %
      ChangeAECO
      natural gas (CDN$/Mcf)
    
    **$**
    **6.79**
    
    $
    6.70
    
    
    1
    %NYMEX
      natural gas (US$/Mcf)
    
    
    **6.09**
    
    
    5.54
    
    
    10
    %NYMEX
      natural gas: CDN$ equivalent (CDN$/Mcf)
    
    
    **7.91**
    
    
    7.69
    
    
    3
    %WTI
      crude oil (US$/bbl)
    
    
    **41.40**
    
    
    31.04
    
    
    33
    %WTI
      crude oil: CDN$ equivalent (CDN$/bbl)
    
    
    **53.77**
    
    
    43.11
    
    
    25
    %CDN$/US$
      exchange rate
    
    **$**
    **0.77**
    
    $
    0.72
    
    
    7
    %
  At the
outset of 2004, the AECO benchmark natural gas price was approximately $7.00/Mcf
due to winter demand, however milder weather caused the prices to retreat to
around $6.00/Mcf. Storage gas was purchased in the initial summer months of
April and May at similarly high prices, but once it became evident there would
be no difficulty in returning storage to normal levels, the price fell to a low
of $5.00/Mcf in September. Winter weather speculation combined with the strength
in the crude oil market returned prices to average greater than $7.00/Mcf during
the last quarter of 2004. Overall, the average annual AECO gas price was only 1%
higher in 2004 compared to 2003.




**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **49**








Our natural gas
selling price increased 4% over the prior year as a result of a portion of our
gas being sold directly into U.S. destinations such as Chicago, which benefited
from the 3% increase in Canadian dollar NYMEX pricing during 2004. As well, the
netbacks we received from our aggregator sales were higher due to the increase
in the NYMEX benchmark price.





As indicated by the
current market for future prices (the “forward market”), AECO natural gas prices
are currently expected to average $6.85/Mcf for 2005. Concerns remain that North
American gas production may not keep pace with demand although, in the near
term, North American storage remains ahead of historical averages. The tight
balance between supply and demand will continue to create volatility whenever
there are unexpected changes to weather, storage or economic activity.





**AECO
Natural Gas Prices**









The crude oil
benchmark West Texas Intermediate (“WTI”) price entered 2004 at US$33.78/bbl,
experienced a peak of US$55.17/bbl late in October and closed the year at
US$43.45/bbl. Overall, WTI prices were 33% higher in 2004 compared to 2003.
Continued instability in the Middle East combined with growing demand from Asia
served to keep prices above US$35.00/bbl throughout 2004.





Approximately 27%
of our liquids production is classified as heavy and as a result, the widening
heavy oil differentials impacted our average crude oil selling price for the
year. For example, the price discount to WTI for the Lloydminster Blend heavy
oil stream increased from US$8.45/bbl to US$13.40/bbl in 2004. These widening
differentials caused our average crude oil prices to increase by only 21%
compared to the WTI benchmark in Canadian dollars which increased 25%.





The forward market
currently predicts crude oil prices will average US$47.82/bbl for 2005.
Increasing demand from China, political and labour unrest in Venezuela and
Nigeria, as well as continued price support from OPEC, keeps upward pressure on
the price of oil despite some indication of adequate short-term storage.





**WTI Crude
Oil Prices**


****





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **50**







Throughout 2004 the
Canadian dollar strengthened 7% against the U.S. dollar. The strengthening
CDN$/US$ exchange rate reduced prices received for our crude oil and a portion
of our natural gas. Most of Canada’s crude oil and natural gas is exported to
the U.S. and is priced with reference to the U.S. dollar denominated benchmarks.
The Canadian dollar’s strengthening against its U.S. counterpart mirrored the
performance of the Euro and many other world currencies during the year. The
CDN$/US$ exchange rate entered 2004 at approximately $0.77, and hit a high of
$0.85 in November as the U.S. continued to face challenges related to its high
government debt and ongoing issues with respect to terrorism. In addition,
higher interest rates in Canada relative to the U.S. increased demand for the
Canadian dollar.





The current forward
market predicts a CDN$/US$ exchange rate of $0.81 for 2005. Recent economic
weakness in Canada’s export sector as a result of the rapid appreciation of the
Canadian dollar has dampened the likelihood that the Canadian government will be
able to continue to increase interest rates relative to the U.S.





**Price Risk
Management**





Enerplus maintains
a commodity price risk management program. It is designed to provide price
protection on a portion of our future production. Typically, a portion of the
pricing upside is surrendered to reduce the cost of protection against a
significant downturn in prices. The program is intended to provide a measure of
stability to our cash distributions and balance sheet. The program also helps
realize the positive economic returns from our capital development and
acquisition activities.





Our commodity price
risk management program incurred cash costs of $96.2 million during 2004
compared to $45.8 million during 2003. The increase in cash costs during 2004
compared to 2003 was primarily due to our three-way crude oil contracts. Record
high oil prices exceeded our calls, which were priced at approximately
US$30/bbl. At the time we entered into the crude oil three-way contracts we,
along with the forward markets, did not expect oil prices to increase much
beyond US$30/bbl for an extended period. We also incurred cash costs on our
natural gas contracts, but to a lesser extent than we experienced in 2003 ($19.9
million in 2004 compared to $30.8 million in 2003). Although some of our natural
gas swaps were out-of-the-money for portions of the year, gas prices tended to
fluctuate within the price range of many of our derivative
instruments.




Risk
      Management Cash Costs ($ millions, except per unit amounts)
    
    **2004**
    
    2003Crude
      oil
    
    **$**
    **76.3**
    ****
    **$**
    **8.16/bbl**
    
    $
    15.0
    
    $
    1.67/bblNatural
      gas
    
    
    **19.9**
    
    **$**
    **0.20/Mcf**
    
    
    30.8
    
    $
    0.35/McfNet
      hedging cost
    
    **$**
    **96.2**
    ****
    **$**
    **3.50/BOE**
    
    $
    45.8
    
    $
    1.81/BOE


****


We
continue to adjust our risk management strategies in response to the high cash
costs experienced in 2004. We view the program as insurance given the historical
volatility associated with oil and gas prices. As we enter 2005, we are less
concerned with utilizing “costless” instruments where the cost of the downside
protection is covered entirely by the value of selling calls (upside price
participation). We are more inclined to buy put protection or put spread
protection and absorb the upfront costs associated with these contracts. We are
also more cautious about selling calls (upside price participation) too early,
as the market has proven it can move dramatically higher than the range of
expectation that had been established 12 to 24 months earlier. Within the
context of these refinements, we intend to continue our commodity price
protection program in 2005. At the current time we do not have any CDN$/US$
exchange rate hedges associated with our revenues.





The
method we use to report the effects of our commodity price risk management
program has changed to reflect the new accounting pronouncements regarding
hedging relationships, which we have adopted prospectively as of January 1,
2004. Enerplus designated derivative instruments such as swaps, purchased puts
and costless collars as qualified hedges for accounting purposes. These
instruments are evaluated quarterly to ensure they effectively hedge the
underlying commodity. All of our other financial instruments such as three-way
option contracts including the purchased puts imbedded within the three-way
options, and the calls or puts we sell, do not qualify as effective hedges for
accounting purposes. The implications of qualifying or not qualifying for hedge
accounting is discussed more fully on the following page.




**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **51**








The
following table summarizes the effects that our financial contracts have had on
income for the years ended December 31, 2004 and 2003.




**2004**
    
    2003*Commodity
      Derivative Instruments
    
    
    **($
      Millions)**
    
    
    **(Per
      BOE)**
    
    
    ($
      Millions)
    
    
    (Per
      BOE)Financial
      contracts not qualifying as hedges:Change
      in fair value - other financial contracts
    
    **$**
    **21.3**
    ****
    **$**
    **0.77**
    
    $
    -
    
    $
    -Amortization
      of deferred financial assets
    
    
    **17.9**
    
    
    **0.65**
    
    
    -
    
    
    -Cash
      costs of financial contracts
    
    
    **78.0**
    
    
    **2.84**
    
    
    -
    
    
    -**$**
    **117.2**
    ****
    **$**
    **4.26**
    
    $
    -
    
    $
    -Financial
      contracts qualifying as hedges:Cash
      costs of financial contracts
    
    
    **18.2**
    
    
    **0.66**
    
    
    45.8
    
    
    1.81Total
      cost of financial contracts
    
    **$**
    **135.4**
    ****
    **$**
    **4.92**
    
    $
    45.8
    
    $
    1.81




*
    The
      new accounting rules were adopted prospectively, therefore only cash costs
      are reflected in 2003.





The unrealized cost
of financial contracts of $21.3 million for the year ended December 31, 2004
represents the change in the fair value of financial contracts not qualifying
for hedge accounting and results in a non-cash charge to earnings.





The amortization of
deferred financial assets is also a result of our adopting the new accounting
rules for hedging relationships. On January 1, 2004, all of our three-way
financial contracts ceased to qualify for hedge accounting. As a result, we
recorded a deferred financial asset representing the fair value of these
contracts on that day. We are amortizing this asset to income over the life of
the underlying contracts for which the deferred asset relates. The asset has
been included in deferred charges and amortization of this asset was $17.9
million for the year ended December 31, 2004, representing another non-cash
charge to earnings.





The cash costs
associated with financial contracts that do not qualify for hedge accounting are
segregated from the costs of financial contracts that do qualify for hedge
accounting. During the year ended December 31, 2004 we realized cash costs of
$78.0 million for financial contracts that do not qualify for hedge accounting
as a result of commodity prices exceeding the ceiling price limits on many of
our three-way contracts.





Cash costs for
financial contracts that qualify for hedge accounting decreased to $18.2 million
for the year ended December 31, 2004 compared to $45.8 million for the year
ended December 31, 2003. This is a result of our three-way crude oil and natural
gas contracts no longer qualifying for hedge accounting during 2004, compared to
2003 when all of our financial contracts qualified for hedge accounting.





Enerplus’ current
commodity risk management positions are fully described in Note 12. The
following is a summary of the physical and financial contracts in place with
floor protection and ceiling caps as a percentage of net production volumes:





2005
    2006Q1
    Q2
    Q3
    Q4
    Q1
    Q2
    Q3
    Q4**Crude
      Oil (bbls/day)**Floor
      protection
    10,500
    12,000
    12,000
    9,000
    4,500
    4,500
    -
    -%
    45%
    56%
    55%
    40%
    21%
    21%
    0%
    0%Upside
      Capped
    10,500
    9,000
    9,000
    6,000
    4,500
    4,500
    -
    -%
    45%
    42%
    41%
    27%
    21%
    21%
    0%
    0%**Natural
      Gas (MMcf/day)**Floor
      protection
    85.5
    85.5
    82.7
    76.3
    35.2
    25.7
    25.7
    25.7%
    39%
    41%
    40%
    35%
    16%
    12%
    12%
    12%Upside
      Capped
    79.2
    76.0
    73.2
    66.9
    35.2
    25.7
    25.7
    25.7%
    36%
    36%
    36%
    31%
    16%
    12%
    12%
    12%





*
    Percentages
      are net of royalties and are based on forecast production including a
      decline rate throughout the year.


**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **52**










We also
entered a swap contract to fix the price of electricity on 5 megawatt hours
(“MWh”), representing 26% of the power consumption of our Alberta operated
properties at a price of $49.99/MWh from January 1, 2005 to December 31, 2006.
The contract has been designated as a hedge and accounted for accordingly. The
fair value of this instrument at December 31, 2004 is negligible. We may enter
into additional electricity price swaps in 2005 to manage the cost of our
operations.





Our
risk management program will reduce, but not eliminate, the effects of changing
prices and exchange rates, and as a result our funds flow remains sensitive to
changes as demonstrated by the following table:




Estimated
      Effect on 2005Sensitivity
      Table
    
    Funds
      Flow per Trust UnitChange
      of $0.15 per Mcf in the price of AECO natural gas
    
    $
    0.08Change
      of US$1.00 per barrel in the price of WTI crude oil
    
    $
    0.05Change
      of 1,000 BOE/day in production
    
    $
    0.09Change
      of $0.01 in the US$/CDN$ exchange rate
    
    $
    0.07Change
      of 1% in interest rate
    
    $
    0.05





These
sensitivities reflect all commodity contracts as described in Note 12 and are
based on current forward markets for 2005. To the extent the market price of
crude oil and natural gas change to levels that are above the ceiling or below
the floor price limits set by existing commodity contracts, the above
sensitivities will no longer be relevant.





**Revenues**





Crude
oil and natural gas revenues for the year ended December 31, 2004 were $1,124.6
million ($1,149.7 million, net of $25.1 million transportation) compared to
$935.8 million ($958.9 million, net of $23.1 million transportation) during
2003. The increase of $188.8 million or 20% is primarily due to higher crude oil
and natural gas prices as well as higher crude oil and natural gas production
resulting from the Ice Energy and ChevronTexaco acquisitions.





Analysis of
      Sales Revenue(1)($ millions)
    
    Crude
      Oil
    
    NGLs
    
    Natural
      Gas
    
    Total2003 Sales
      Revenue
    
    $
    324.5
    
    $
    56.9
    
    $
    554.4
    
    $
    935.8Price
      variance(1)
    
    
    71.5
    
    
    7.6
    
    
    25.8
    
    
    104.9Volume
      variance
    
    
    13.5
    
    
    (3.1
    )
    
    73.5
    
    
    83.9**2004
      Sales Revenue**
    ****
    **$**
    **409.5**
    ****
    **$**
    **61.4**
    ****
    **$**
    **653.7**
    ****
    **$**
    **1,124.6**





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





**Royalties**





Royalties
are paid to various government entities and other land and mineral rights
owners. In 2004 royalties increased to $231.0 million compared to $190.4 million
during 2003, both approximately 20% of oil and gas sales, net of transportation.
The increase is consistent with our revenue analysis of higher production and
commodity prices during 2004. We expect royalties to remain at approximately 20%
of gross oil and gas sales during 2005.





**Operating
Expenses**





Operating
expenses for the year ended December 31, 2004 were $196.5 million or $7.14/BOE
compared to $170.5 million or $6.73/BOE in 2003, representing a 6% increase on a
BOE basis. In particular, we experienced increased costs for well servicing,
workovers and well maintenance as additional funds were spent to enhance
production. Operating costs on our partner operated properties also continued to
increase as high commodity prices fueled demand for services and increased the
overall cost of maintaining and enhancing production. We expect 2005 operating
costs to be approximately $7.45/BOE which represents an increase of 4% per BOE
compared to 2004.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **53**










**General
and Administrative Expenses**





General
and administrative (“G&A”) expenses were $33.9 million or $1.23/BOE for the
year ended December 31, 2004 compared to $25.4 million or $1.00/BOE for 2003.
The increase in G&A costs during 2004 compared to 2003 can be attributed to
both an increase in G&A cash costs along with an increase in non-cash
charges. Increased cost pressures associated with maintaining skilled technical
and professional staff along with increased compliance and regulatory
requirements such as the Sarbanes-Oxley Act increased cash costs from $0.95/BOE
in 2003 to $1.06/BOE in 2004.





Non-cash
charges that relate to our trust unit rights incentive plan for the year ended
December 31, 2004 were $4.7 million or $0.17/BOE compared to $1.4 million or
$0.05/BOE for 2003. This non-cash charge relates to trust unit rights issued
after January 1, 2003 and is based on the excess of the trust unit price at
December 31, 2004 of $43.60 over the exercise price of the right, amortized over
the remaining vesting period. This non-cash charge will increase or decrease
along with the movement in the price of the underlying trust units. See Note
10.





The
following table summarizes the cash and non-cash expenses recorded in
G&A:





General and
      Administrative Costs ($ millions)
    
    **2004**
    
    2003Cash
    
    **$**
    **29.2**
    
    $
    24.0Trust unit
      rights incentive plan (non-cash)
    
    
    **4.7**
    
    
    1.4Total
      G&A
    
    **$**
    **33.9**
    
    $
    25.4





We
expect total G&A costs to be approximately $1.45/BOE during 2005, which
includes non-cash charges for the trust unit rights plan similar to that
experienced during 2004. The forecasted increase reflects rising costs
associated with recruiting, retaining and developing staff within a very
competitive market place. It also reflects the increasing costs of compliance
with legal and regulatory changes such as the Sarbanes-Oxley Act and other
similar legislation in Canada.





**Management
Fees and Internalization Expense**





During
2004 no management fees were incurred compared to $58.1 million during 2003,
which included $3.0 million in management fees and $55.1 million of
internalization costs. This is a result of the internalization of the management
contract effective April 23, 2003.





**Interest
Expense**





Interest
expense increased to $20.7 million in 2004 from $19.7 million in 2003. The
increase is due to higher average debt outstanding during 2004 as a result of
acquiring ChevronTexaco properties on June 30, 2004 offset by lower interest
rates during the year. At December 31, 2004, 24% of our debt was based on fixed
interest rates while 76% was floating. These instruments are more fully
described in Note 12.





The
Bank of Canada (“BOC”) prime rate increased 25 basis points on October 19, 2004
to 4.25%, however the BOC has deferred further interest rate increases due to
the strengthening Canadian dollar and its negative impact on the economy. We
anticipate interest rates to remain at current levels during 2005.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **54**







**Foreign
Exchange**





We
experienced a foreign exchange gain of $5.0 million during the year ended
December 31, 2004 compared to a gain of $0.9 million in 2003. The majority of
the gain during 2004 was a result of non-cash items related to the appreciating
Canadian dollar and its impact when translating our US$54 million senior
unsecured notes. We realized minimal foreign exchange gains or losses on
day-to-day transactions denominated in U.S. dollars. See Note 9 for details
regarding the cash and non-cash gains.





**Capital
Expenditures**





During
the year ended December 31, 2004
we spent $813.6 million on capital expenditures and acquisitions net of dispositions compared to $312.1
million in 2003. As discussed in Notes 6 and 7, our most significant
acquisitions during 2004 relate to the ChevronTexaco
properties purchased for $467.2 million and the corporate acquisition of Ice
Energy for $130.5 million . Our
capital expenditures were financed through bank borrowing, a new equity issue
and by withholding a portion of cash otherwise available for distribution.





Capital
      Expenditures ($ millions)
    
    **2004**
    
    2003Development
      expenditures
    
    **$**
    **157.7**
    
    $
    115.6Plant
      and facilities
    
    
    **49.1**
    
    
    42.1Sub-total
    
    
    **206.8**
    
    
    157.7Office
    
    
    **2.2**
    
    
    2.3Sub-total
    
    
    **209.0**
    
    
    160.0Acquisitions
      of oil and gas properties
    
    
    **505.8**
    
    
    58.4Corporate
      acquisitions
    
    
    **130.5**
    
    
    166.9Dispositions
      of oil and gas properties
    
    
    **(31.7**
    **)**
    
    (73.2
    )Total
      Net Capital Expenditures
    
    **$**
    **813.6**
    
    $
    312.1




The
following is a summary by major property of our largest capital expenditures
during 2004 and 2003.




($
      millions)
    
    Development
      Type
    
    **2004**
    
    2003Shackleton
    
    
    Shallow
      gas
    
    **$**
    **14.3**
    
    $
    -Deep
      Basin
    
    
    Foothills
      gas
    
    
    **13.9**
    
    
    11.2Medicine
      Hat
    
    
    Shallow
      gas
    
    
    **12.4**
    
    
    11.6Bantry
    
    
    Shallow
      and other gas
    
    
    **12.0**
    
    
    10.9Hanna/Garden
      Plains
    
    
    Shallow
      and other gas
    
    
    **11.4**
    
    
    6.7Joarcam
    
    
    Oil
      waterflood
    
    
    **9.0**
    
    
    3.7Pembina
      5-Way
    
    
    Oil
      waterflood
    
    
    **8.8**
    
    
    4.6Verger
    
    
    Shallow
      gas
    
    
    **8.3**
    
    
    5.3Joslyn
      Creek
    
    
    SAGD
      oil
    
    
    **8.3**
    
    
    4.2Progress
    
    
    Oil
      and gas
    
    
    **6.5**
    
    
    6.6Other
    
    
    Oil
      and gas
    
    
    **101.9**
    
    
    92.9Total
    
    
    
    
    **$**
    **206.8**
    
    $
    157.7





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **55**










Total
capital expenditures in 2005, including directly related administrative costs,
are expected to be approximately $275 million. Of this amount, we expect to
spend about $245 million on oil and natural gas drilling, facilities and
development activities, and approximately $30 million to further develop our
pilot project at Joslyn Creek. Of the $245 million approximately $135 million
will be spent on natural gas development including $25 million on coalbed
methane development at Joffre, Trochu and Bashaw. Conventional oil development
costs are expected to be approximately $100 million, and land and seismic
expenditures are expected to be approximately $10 million.





In
2004, we sold $31.7 million worth of non-core properties and we expect to
continue the process of acquiring new properties and rationalizing marginal
properties in 2005. During the first quarter of 2005 we expect to sell
approximately $60 million of non-core properties that are currently producing
approximately 2,500 BOE/day.





**Asset
Retirement Obligations**





We
retroactively adopted Canadian Institute of Chartered Accountants (“CICA”)
Handbook section 3110 “Asset Retirement Obligations” on January 1, 2004 and
accrued a $63.9 million liability in this regard for December 31, 2003. We based
our estimated costs for abandonment on the costs provided by the Alberta Energy
and Utilities Board (“EUB”) in their liability rating. During the course of the
year, the EUB increased their estimates for abandonment and reclamation costs,
which we have incorporated in our asset retirement obligation estimate as at
December 31, 2004. The change in EUB estimates resulted in $23.1 million being
added to the liability. Acquisition and development activity during the year
added another $20.7 million to asset retirement obligations. As at December 31,
2004 our asset retirement obligation was $106.0 million. See Notes 2 and
4.





**Depletion,
Depreciation, Amortization and Accretion (“DDA&A”)**





DDA&A
of property, plant and equipment is recognized using the unit-of-production
method based on proved reserves.





For the
year ended December 31, 2004, DDA&A increased to $11.87/BOE compared to
$9.67/BOE during the year ended December 31, 2003. The increase is due to the
acquisitions of ChevronTexaco properties and Ice Energy, as well as higher
production volumes and an increase in our asset retirement obligation.
Furthermore, proved reserves used in the depletion calculation decreased due to
the adoption of National Instrument 51-101 (“NI 51-101”) at December 31, 2003.
As a result, DDA&A recorded during the year ended December 31, 2004 was
significantly higher than the comparable period of 2003, which was based on
reserves prior to the adoption of NI 51-101.





No
impairment existed at December 31, 2004 using year-end reserves and management’s
estimates of future prices. Our future price estimates are more fully discussed
in Note 5.





**Taxes**





Capital
taxes, consisting of the Federal Large Corporations Tax (“LCT”) and the
Saskatchewan Resource Surcharge, increased slightly in 2004 compared to 2003.
The increase is due to an increase in total debt and equity levels, as a result
of acquisitions, offset by a reduction in the tax rate for LCT. Given our
current capital structure, capital taxes are expected to be **** $6.0
million **** in
2005.





Future
income taxes arise from differences between the accounting and tax bases of the
operating companies’ assets and liabilities. In our current structure, payments
are made between the operating entities and the Fund, ultimately transferring
both income and future income tax liability to our unitholders. Therefore, it is
our opinion that no cash income taxes are expected to be paid by the operating
entities in the future, and as such, the future income tax liability recorded on
the balance sheet should be recovered through earnings over time.





For the
year ended December 31, 2004, a future income tax recovery of $76.8 million was
recorded in income compared to $71.6 million in 2003. The increased recovery in
2004 was mainly the result of increased net income of the Fund during 2004. Our
expected future income tax rate incorporating these changes is approximately 34%
compared to 35% at December 31, 2003.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **56**





**Selected
Financial Results**





Per
      BOE of production (6:1)
    
    **2004**
    
    2003Production
      per day
    
    
    **75,130**
    
    
    69,414Weighted
      average sales price(1)
    
    **$******
    ******40.90**
    
    $
    36.94Royalties
    
    
    **(8.40**
    **)**
    
    (7.51
    )Financial
      contracts
    
    
    **(4.92**
    **)**
    
    (1.81
    )Add
      back: Non-cash financial contracts
    
    
    **1.42**
    
    
    -Operating
      costs
    
    
    **(7.14**
    **)**
    
    (6.73
    )General
      and administrative
    
    
    **(1.23**
    **)**
    
    (1.00
    )Add
      back: Non-cash G&A expense (trust unit rights)
    
    
    **0.17**
    
    
    0.05Management
      fees and internalization
    
    
    -
    
    
    (2.29
    )Interest
      expense, net of interest and other income
    
    
    **(0.68**
    **)**
    
    (0.74
    )Foreign
      exchange gain
    
    
    **0.18**
    
    
    0.04Deduct:
      Non-cash foreign exchange gain
    
    
    **(0.17**
    **)**
    
    (0.12
    )Capital
      taxes
    
    
    **(0.24**
    **)**
    
    (0.26
    )Restoration
      and abandonment cash costs
    
    
    **(0.25**
    **)**
    
    (0.26
    )**Funds
      flow from operations**
    
    
    **19.64**
    
    
    16.31Restoration
      and abandonment cash costs
    
    
    **0.25**
    
    
    0.26Non-cash
      items:Depletion,
      depreciation, amortization and accretion
    
    
    **(11.87**
    **)**
    
    (9.67
    )Financial
      contracts
    
    
    **(1.42**
    **)**
    
    -G&A
      expense (trust unit rights)
    
    
    **(0.17**
    **)**
    
    (0.05
    )Foreign
      exchange
    
    
    **0.17**
    
    
    0.12Future
      income tax recovery
    
    
    **2.79**
    
    
    2.82**Total
      net income per BOE**
    
    **$******
    ******9.39**
    
    $
    9.79




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





**Net
Income and Funds Flow From Operations**




Higher
production volumes and more favourable commodity prices helped to increase oil
and natural gas sales and net income for 2004 compared to 2003. The following
table summarizes net income, funds flow from operations and other key measures
for the last three years.




($ millions,
      except per unit amounts)
    
    
    **2004**
    
    
    2003
    
    
    2002(restated,
      Note 2)
    
    
    (restated,
      Note 2)Oil
      and gas sales(1)
    
    **$**
    **1,124.6**
    
    $
    935.8
    
    $
    630.2Net
      income
    
    **$**
    **258.3**
    
    $
    248.0
    
    $
    116.6Per
      unit (Basic)
    
    **$**
    **2.60**
    
    $
    2.88
    
    $
    1.62Per
      unit (Diluted)
    
    **$**
    **2.60**
    
    $
    2.87
    
    $
    1.62Funds
      flow from operations
    
    **$**
    **540.0**
    
    $
    413.2
    
    $
    289.9Per
      unit (Basic)
    
    **$**
    **5.44**
    
    $
    4.79
    
    $
    4.03Cash
      available for distribution
    
    **$**
    **426.7**
    
    $
    379.1
    
    $
    246.8Per
      unit (Basic)
    
    **$**
    **4.20**
    
    $
    4.32
    
    $
    3.32Payout
      ratio
    
    
    **79**
    **%**
    
    92
    %
    
    84
    %Total
      assets
    
    **$**
    **3,180.7**
    
    $
    2,661.8
    
    $
    2,518.0Long-term
      debt, net of cash
    
    **$**
    **585.0**
    
    $
    257.7
    
    $
    361.0




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





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **57**










Funds
flow from operations for the year ended December 31, 2004 was $540.0 million or
$5.44 per trust unit compared to $413.2 million or $4.79 per trust unit for
2003. The increase in funds flow from operations was a result of higher
commodity prices and production during 2004 compared to 2003, offset in part by
the cash losses from our commodity price risk management program, along with
higher operating and G&A costs. As well, the internalization of the
management contract, which occurred during 2003, reduced the comparative period
results for the year ended December 31, 2003.





Net
income for the year ended December 31, 2004 was $258.3 million or $2.60 per
trust unit compared to $248.0 million or $2.88 per trust unit for
2003. The increase in net income for the year ended December 31, 2004 was due to
higher commodity prices and production,
no management fees due to the internalization completed in 2003, as well as an
increase in our future tax recovery. This was offset by increases in operating
costs, depletion expense and G&A costs, as well as changes in accounting for
our derivative instruments. The decrease in net income per trust unit was due to
an increase in the weighted average number of trust units outstanding.





**Quarterly
Financial Information**





Overall
oil and gas sales have increased due to higher prices and production both
through acquisitions and capital development throughout the last two years,
offset by an increased Canadian/U.S. dollar exchange rate. Net income has been
affected by the fluctuations in oil and gas sales, the increase in risk
management costs, the strengthening Canadian dollar, the internalization of the
management contract during 2003, increasing operating costs, increased future
tax recovery and changes to accounting policies adopted during 2003 and 2004.




Quarterly
      Financial Information
    
    
    Oil
      and Gas
    
    
    Net
    
    Net
      income per trust unit($
      millions, except per trust unit amounts)
    
    
    Sales(1)
    
    
    Income
    
    
    Basic
    
    
    Diluted**2004**First
      quarter
    
    **$**
    **239.3**
    ****
    **$**
    **45.2**
    ****
    **$**
    **0.48**
    ****
    **$**
    **0.48**Second
      quarter
    
    
    **265.6**
    
    
    **48.0**
    
    
    **0.51**
    
    
    **0.51**Third
      quarter
    
    
    **302.2**
    
    
    **50.6**
    
    
    **0.49**
    
    
    **0.49**Fourth
      quarter
    
    
    **317.5**
    
    
    **114.5**
    
    
    **1.10**
    
    
    **1.10****Total**
    
    **$**
    **1,124.6**
    ****
    **$**
    **258.3**
    ****
    **$**
    **2.60**
    ****
    **$**
    **2.60**2003
      (Restated)First
      quarter
    
    $
    281.1
    
    $
    94.8
    
    $
    1.14
    
    $
    1.14Second
      quarter
    
    
    233.5
    
    
    53.4
    
    
    0.64
    
    
    0.64Third
      quarter
    
    
    219.7
    
    
    59.2
    
    
    0.67
    
    
    0.67Fourth
      quarter
    
    
    201.5
    
    
    40.6
    
    
    0.45
    
    
    0.45Total
    
    $
    935.8
    
    $
    248.0
    
    $
    2.88
    
    $
    2.87





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





**Summary
Fourth Quarter Information**





In
comparing the fourth quarter of 2004 with the same period in 2003:





•
    Funds
      flow from operations increased 71% to $149.4 million and 46% on a BOE
      basis as a result of higher production and selling prices;•
    Average
      daily production increased 17%due tothe
      acquisition of Ice Energy and the ChevronTexaco properties as well
      asa successful capital development program;•
    The
      average selling price per BOE increased 35% due to stronger crude oil and
      natural gas prices;•
    Operating
      expenses decreased 13%to
      $6.93/BOE as the fourth quarter of 2003 was impacted by a number of
      one-time prior period charges;





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **58**










•
    G&A
      expenses increased 35% to$1.59/BOE,
      as thefourth
      quarter of 2004 was impacted by increased charges for unit based
      compensation related to the higher trust unit priceand performance achieved by the Fund;•
    Net
      income increased 182% to $114.5 million; and•
    Development
      capital spending increased 78% as we had a larger development program in
      2004, and more of that program was directed to the fourth quarter in
      response to drilling plans, rig availability and weather related
      timing.





**Three**
    
    ThreeSummary
      Fourth Quarter Information
    
    **Months
      Ended**
    
    Months
      Ended
    
    %($
      millions, except per unit amounts)
    
    **December
      2004**
    
    December
      2003
    
    Change**Daily
      Production Volumes**Natural
      gas (Mcf/day)
    
    
    **292,671**
    
    
    243,573
    
    
    20
    %Crude
      oil (bbls/day)
    
    
    **28,752**
    
    
    24,477
    
    
    17
    %Natural
      gas liquids (bbls/day)
    
    
    **4,157**
    
    
    4,768
    
    
    (13
    %)Total
      daily sales (BOE/day)
    
    
    **81,688**
    
    
    69,841
    
    
    17
    %**Average
      Selling Price****(1)**Natural
      gas (per Mcf)
    
    **$**
    **6.59**
    
    $
    5.10
    
    
    29
    %Crude
      oil (per bbl)
    
    
    **46.20**
    
    
    31.58
    
    
    46
    %Natural
      gas liquids (per bbl)
    
    
    **45.46**
    
    
    35.66
    
    
    27
    %Per
      BOE
    
    **$**
    **42.25**
    
    $
    31.36
    
    
    35
    %**Revenue****(1)**
    
    **$**
    **317.5**
    
    $
    201.5
    
    
    58
    %Per
      BOE
    
    **$**
    **42.25**
    
    $
    31.36
    
    
    35
    %**Operating
      Expenses**
    
    **$**
    **52.1**
    
    $
    51.3
    
    
    2
    %Per
      BOE
    
    **$**
    **6.93**
    
    $
    7.98
    
    
    (13
    %)**General
      and Administrative Expenses**
    
    **$**
    **11.9**
    
    $
    7.6
    
    
    57
    %Per
      BOE
    
    **$**
    **1.59**
    
    $
    1.18
    
    
    35
    %**Net
      Income**
    
    **$**
    **114.5**
    
    $
    40.6
    
    
    182
    %Per
      BOE
    
    **$**
    **15.24**
    
    $
    6.32
    
    
    141
    %**Funds
      Flow from Operations**
    
    **$**
    **149.4**
    
    $
    87.3
    
    
    71
    %Per
      BOE
    
    **$**
    **19.88**
    
    $
    13.58
    
    
    46
    %**Development
      Capital Spending**
    
    **$**
    **74.9**
    
    $
    42.0
    
    
    78
    %**Acquisitions**
    
    **$**
    **14.5**
    
    $
    13.7
    
    
    6
    %**Divestments**
    
    **$**
    **12.7**
    
    $
    26.0
    
    
    (51
    %)





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





**Cash
Available for Distribution**





We make
monthly cash distributions to our unitholders based upon net funds flow from our
crude oil and natural gas operations. A portion of funds flow is typically
retained to fund some of our acquisition and development activities. For the
year ended December 31, 2004, we generated
$540.0 million in funds flow from operations. Of this amount, $426.7 million
($4.20 per trust unit) was paid to unitholders and $113.3 million ($1.11 per
trust unit) was retained .





We
monitor the distribution payout with respect to forecasted funds flows, debt
levels and spending plans. The level of cash retained typically varies between
10% and 30% of annual funds flow, however we are 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.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **59**







The
following table reconciles Enerplus’ funds flow from operations with the cash
available for distribution to unitholders.





Reconciliation
      of Cash Available for Distribution ($ millions, except per unit
      amounts)
    
    **2004**
    
    2003Funds
      flow from operations before internalization of management
      contract
    
    **$**
    **540.0**
    
    $
    468.3Management
      internalization costs
    
    
    **-**
    
    
    (55.1
    )Funds
      flow from operations
    
    
    **540.0**
    
    
    413.2Cash
      withheld for acquisitions and capital expenditures
    
    
    **(113.3**
    **)**
    
    (34.1
    )Cash
      available for distribution*
    
    **$**
    **426.7**
    
    $
    379.1Cash
      available for distribution per trust unit
    
    **$**
    **4.20**
    
    $
    4.32





*
    Cash available
      for distribution will differ from Cash Distributions to Unitholders on the
      Consolidated Statements of Cash Flows due to the timing of distribution
      declaration and actual payments.





**Liquidity
and Capital Resources**





Long-term
debt at December
31, 2004 was $585.0 million , an
increase of $246.9 million from December 31, 2003. The increase in debt is
primarily the result of the ChevronTexaco and Ice Energy acquisitions, which
were funded by both bank debt and equity. Furthermore, long-term debt levels at
the end of 2003 were lower than normal due to an equity issue that closed
December 17, 2003 in advance of the Ice Energy acquisition.





Long-term
debt at December 31, 2004 is comprise d
of $251.7 m illion
of bank indebtedness and $65.0 million and $268.3 million of Canadian dollar
equivalent debt related to the US$54 million and US$175 million senior unsecured
notes, respectively.





Working
capital declined at December 31, 2004 compared to the prior year. At the end of
December 31, 2003 we had cash of $80 million from an equity issue that had
closed just prior to year-end. In addition, working capital was reduced as a
result of new accounting pronouncements during 2004 with respect to derivative
instruments. The fair value of the instruments that do not qualify as hedges
have been recorded as deferred credits and are included in current liabilities,
however these costs will fluctuate depending on the commodity prices at the time
of settlement and will be paid from future production which is not yet recorded
in the financial statements.





We
continue to maintain a conservative balance sheet as demonstrated
below:





**Year
      ended**
    
    Year
      ended**Financial
      Leverage and Coverage**
    
    **Dec.
      31, 2004**
    
    Dec.
      31, 2003Long-term
      debt to trailing funds flow
    
    
    **1.1**
    **x**
    
    0.6
    xFunds flow to
      interest expense
    
    
    **26.0**
    **x**
    
    21.0
    xLong-term
      debt to long-term debt plus equity
    
    
    **23**
    **%**
    
    12
    %


****


Long-term debt is
measured net of cash.****





In
November 2004, Enerplus finalized a new $850 million bank credit facility (the
“Bank Credit Facility”) through its wholly-owned subsidiary EnerMark Inc. The
Bank Credit Facility is an unsecured, covenant-based, three-year committed
credit agreement with nine North American banks. We have the ability to extend
the facility each year or repay the entire balance at the end of the three-year
term. As at December 31, 2004, we had $598.3 million of available borrowing
capacity under this facility. This bank debt carries floating interest rates
that are expected to range between 65 and 87.5 basis points over Bankers
Acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before
interest, taxes, depreciation, amortization and other non-cash
items.





The new
agreement increased our borrowing capacity and extended the term of our
facility. Furthermore, we are no longer restricted to borrowing base evaluations
that are determined using the banks’ commodity price outlook. Although there are
certain exceptions, we are generally required to maintain a debt to funds flow
ratio of less than three times, and a debt to capitalization of less than 50%.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **60**







The Bank Credit
Facility and the Senior Unsecured Notes are the legal obligation of EnerMark
Inc. and are guaranteed by Enerplus Resources Corporation and Enerplus
Commercial Trust. Payments with respect to the bank facilities, senior unsecured
notes and other third party debt have priority over claims of and future
distributions to the unitholders. Unitholders have no direct liability should
funds flow be insufficient to repay this indebtedness. The agreements governing
these bank facilities and senior unsecured notes stipulate that if we default or
fail to comply with certain covenants, the ability of the operating companies to
make payments to the Fund and consequently the Fund’s ability to make
distributions to the unitholders may be restricted.





Principal payments
on Enerplus’ senior unsecured notes are required commencing in 2010 and 2011 and
are more fully discussed in Note 8.





On June 15, 2004,
we completed an equity offering of 8.8 million subscription receipts at a price
of $34.30 per subscription receipt. Each subscription receipt entitled the
holder to receive one trust unit of the Fund upon closing of the ChevronTexaco
asset acquisition. All subscription receipts were converted to trust units on
June 30, 2004 and gross proceeds of the issue were $301.8 million ($286.2
million net of issuance costs).





We anticipate that
we will continue to have adequate liquidity to fund future working capital and
planned capital expenditures during 2005 through a combination of funds flow
from operations, proceeds from dispositions and debt. Most of Enerplus’ $275
million capital budget for 2005 is discretionary and can be revised downward in
the event of a significant commodity price downturn or similar economic event.
We have historically demonstrated our ability to finance acquisitions and other
future commitments through a combination of debt, equity and funds flow from
operations.





**Commitments**





We have contracted
to transport natural gas with various pipelines totaling 15 MMcf per day until
2008 and a further 5 MMcf per day until 2015. These transportation contracts
will cost approximately $5.6 million in 2005.





Enerplus has an
office lease commitment that extends to November 30, 2009. Annual costs of this
lease commitment, which include rent and operating fees, amount to approximately
$4.6 million. The Fund’s commitments, contingencies, and guarantees are more
fully described in Note 13.





We must
continue to pay crown royalties and rentals, surface royalties and rentals,
mineral taxes and abandonment and reclamation costs with respect to our ongoing
ownership of hydrocarbon production rights. The amounts paid with respect to
these burdens will depend on the future ownership, production, prices and
legislative environment at the time.





Natural
gas reserves producing approximately 31% of our current production are dedicated
to certain aggregator sales arrangements. Under these arrangements, we receive a
price based on the average netback price of the pool, net of transportation
costs incurred by the aggregator for the life of the reserves.





Enerplus
has the following minimum annual commitments including long-term
debt:




TotalMinimum
      Annual Commitment Each Year
    
    
    Committed($
      millions)
    
    
    **Total**
    
    
    2005,
      2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    after
      2009Bank
      credit facility
    
    **$**
    **251.7**
    
    $
    -
    
    $
    251.7
    
    $
    -
    
    $
    -
    
    $
    -Senior
      unsecured notes
    
    
    **333.3**
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    333.3Pipeline
      commitments
    
    
    **37.9**
    
    
    5.6
    
    
    5.6
    
    
    5.0
    
    
    2.4
    
    
    13.7Office
      lease
    
    
    **22.5**
    
    
    4.7
    
    
    4.5
    
    
    4.5
    
    
    4.1
    
    
    -Total
      commitments
    
    **$**
    **645.4**
    
    $
    10.3
    
    $
    261.8
    
    $
    9.5
    
    $
    6.5
    
    $
    347.0


**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **61**





**Trust Unit
Information**





We had 104,124,000
trust units outstanding at December 31, 2004 compared to 94,349,000 trust units
at December 31, 2003, reflecting the equity offering completed during the year.
The weighted average basic number of trust units outstanding during 2004 was
99,273,000 (2003 - 86,202,000).





In addition to the
equity offering during the year 957,000 trust units (2003 - 1,515,000) were
issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit
Purchase Plan (“DRIP”) and the trust unit options and rights plans. This
resulted in $28.3 million (2003 - $40.4 million) of additional equity to the
Fund. A total of 25,000 units with a value of $0.9 million were issued to
acquire corporate and property interests during 2004 compared to 660,000 units
with a value of $21.4 million issued during 2003.





**Income
Taxes**





The following is 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. Investors 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.





In computing
income, unitholders are required to include 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 trust 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.





We paid $4.20 per
trust unit in cash distributions to unitholders during the period February 2004
to January 2005. For Canadian tax purposes, 10% of these distributions, or $0.43
per trust unit was a tax deferred return of capital, 88% or $3.68 per trust unit
was taxable to unitholders as other income, and 2% or $0.09 per trust unit was
taxable dividend income.





For 2005, we
estimate that 95% of cash distributions may be taxable and 5% may be a tax
deferred return of capital. Actual taxable amounts may vary depending on actual
distributions which are dependent upon production, commodity prices and funds
flow experienced throughout the year.





U.S.
Taxpayers





During 2004 U.S.
unitholders who received cash distributions were subject to at least 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 determined is considered to be a dividend
for U.S. tax purposes. For most U.S. taxpayers, this should be a “Qualified
Dividend” eligible for the reduced tax rate. We believe Enerplus should not be
classified as a Passive Foreign Investment Company for U.S. income tax purposes
for 2004 and 2003.





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
      RESOURCES FUND 2004 ANNUAL REPORT**
    **62**







We paid US$3.22 per
trust unit to U.S. residents during the 2004 calendar year, of which 6% or
US$0.19 per trust unit was a tax deferred return of capital and 94% or US$3.03
per unit was a taxable qualified dividend.





On September 16,
2004, the Canadian Federal Government released draft legislation with respect to
the March 2004 Budget. The draft legislation amends certain provisions of the
Income Tax Act that would affect the taxation of distributions to non-resident
unitholders.





The draft
legislation is expected to be passed into law during the first quarter of 2005.
As currently drafted, a 15% Canadian withholding tax will be applicable,
effective January 1, 2005, to the non-taxable portion of distributions to
non-resident unitholders (which is currently estimated to be 5% of
distributions). This is in addition to the existing 15% withholding tax on the
portion of the distribution designated as income. It is contemplated, however,
that there will be a mechanism under which certain non-residents may recover all
or a portion of such taxes where the ultimate disposition of the trust unit
results in a loss for Canadian tax purposes.





For 2005, we
estimate that 95% of cash distributions may be taxable to most U.S. investors
and 5% may be a tax deferred return of capital. Actual taxable amounts may vary
depending on actual distributions which are dependant upon production, commodity
prices and funds flow experienced throughout the year.




**Critical
Accounting Policies**




The financial
statements have been prepared in accordance with GAAP. A summary of significant
accounting policies is presented in Note 1. A reconciliation of differences
between Canadian and United States GAAP is presented in Note 14. Most accounting
policies are mandated under GAAP. However, in accounting for oil and gas
activities, we have a choice between two acceptable accounting policies: the
full cost and the successful effort methods of accounting.




We follow the full
cost method of accounting for oil and natural gas activities. Using the full
cost method of accounting, all costs of acquiring, exploring and developing oil
and natural gas properties are capitalized, including unsuccessful drilling
costs and administrative costs associated with acquisitions and development.
Under the successful efforts method of accounting, all exploration costs, except
costs associated with drilling successful exploration wells, are expensed in the
period in which they are incurred. The difference between these two
methodologies is not expected to be significant to the Fund’s net income or net
income per unit as the majority of the Fund’s drilling activity is in low risk
development drilling that has traditionally achieved high success
rates.




Under the full cost
method of accounting, an impairment test is applied to the overall carrying
value of property, plant and equipment, for a Canada-wide cost centre with the
reserves valued using estimated future commodity prices at period end. Under the
successful efforts method of accounting, the costs are aggregated on a
property-by-property basis. The carrying value of each property is subject to an
impairment test. Each policy may generate a different carrying value of
property, plant and equipment and a different net income depending on the
circumstances at period end.




**Critical
Accounting Estimates**




The preparation of
financial statements in accordance with GAAP requires management to make certain
judgements and estimates. Due to the timing of when activities occur compared to
the reporting of those activities, we estimate and accrue operating results and
capital spending. Changes in these judgements and estimates could have a
material impact on our****financial results and financial
condition.




The process of
estimating reserves is critical to several accounting estimates. It requires
significant judgements based on available geological, geophysical, engineering
and economic data. These estimates may change substantially as data from ongoing
development and production activities becomes available, and as economic
conditions impacting oil and gas prices, operating


**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **63**




costs and royalty
burdens change. Reserve estimates impact net income through depletion, the
determination of asset retirement obligations and the application of an
impairment test. Revisions or changes in the reserve estimates can have either a
positive or a negative impact on net income and the asset retirement
obligation.





We calculate our
asset retirement obligation based on the estimated costs to abandon and reclaim
our net ownership interest in all wells and facilities and the estimated timing
of the costs to be incurred in future periods. The fair value estimate is
capitalized to property, plant and equipment as part of the cost of the related
asset and amortized over its useful life.




Our estimates of
oil and natural gas prices are also critical as these prices are used to
determine the carrying amount of property, plant and equipment, amounts recorded
for depletion, impairment in the cost centre, and the change in fair value of
financial contracts that do not qualify for hedge accounting.





**Recent
Canadian Accounting and Related Pronouncements**





**Asset
Retirement Obligations**





In December 2002,
the CICA issued Handbook Section 3110, “Asset Retirement Obligations”. This
standard requires recognition of a liability representing the fair value of the
future retirement obligations associated with property, plant and equipment.
This fair value is capitalized and amortized over the same period as the
underlying asset. The standard is effective for all fiscal years beginning on or
after January 1, 2004. We adopted the standard


January 1, 2004.
See Notes 2 and 4.





**Hedging
Relationships**





In November 2002,
the CICA published an amended Accounting Guideline 13 (“AcG-13”), “Hedging
Relationships”. The guideline establishes conditions where hedge accounting may
be applied. It is effective for years beginning on or after July 1, 2003. The
guideline impacted the Fund’s net income and net income per trust unit, as
certain financial instruments for oil and natural gas do not qualify for hedge
accounting. See Note 12. Where hedge accounting does not apply, any changes in
the fair values of the financial instruments relating to a period can either
reduce or increase net income for that period. We adopted this standard January
1, 2004, which has resulted in a reduction in our pre-tax income of $39.2
million.





**Variable
Interest Entities (“VIEs”)**





In June 2003 the
CICA issued Accounting Guideline 15 (“AcG-15”) “Consolidation of Variable
Interest Entities”. AcG-15 defines VIEs as entities in which either; the equity
at risk is not sufficient to permit that entity to finance its activities
without additional financial support from other parties; or equity investors
lack voting control, an obligation to absorb expected losses or the right to
receive expected residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and
provides guidance for companies consolidating VIEs in which it is the primary
beneficiary. The guideline is effective for all annual and interim periods
beginning on or after November 1, 2004. We do not expect this guideline to have
a material impact on the Fund.





**Earnings
per Share**





In July 2004 the
CICA proposed to amend Handbook Section 3500 “Earnings per Share”, to reflect
similar amendments adopted by the International Accounting Standards Board and
proposed by the U.S. Financial Accounting Standards Board. The majority of the
amendments relate to the treatment of mandatorily convertible instruments. The
CICA expects changes to be effective for interim and annual periods relating to
fiscal years beginning on or after January 1, 2005. We currently do not have any
mandatorily convertible instruments and therefore do not expect these amendments
to have a material impact on the Fund.





**Financial
Instruments - Recognition and Measurement, Hedges, and Comprehensive
Income**





The Accounting
Standards Board (“AcSB”) has issued three exposure drafts on financial
instruments which will apply to interim and annual financial statements relating
to fiscal years beginning on or after October 1, 2006. It will require the
following:





•
    all
      trading financial instruments will be recognized on the balance sheet and
      will be fair valued through the income statement;




**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **64**








•
    all
      remaining financial assets will be recorded at cost and amortized through
      the financial statements;•
    a
      new statement for comprehensive income that will include certain gains and
      losses on translation of assets and liabilities; and•
    an
      update to AcG-13 to incorporate the fair value changes not recorded in the
      income statement to be recorded through the comprehensive income
      statement.





We have
not assessed the future impact on the financial statements of the Fund at this
time.





**Changes
in Accounting Policies and Estimates and Errors**





The
AcSB has proposed a new Handbook section 1506 “Changes in accounting policies
and estimates, and errors” to provide guidance around when and how an entity is
permitted to change an accounting policy as well as establish appropriate
disclosures to explain the effects of changes in accounting policy, estimates
and corrections of errors.





**Subsequent
Events**





The
AcSB has proposed to extend the period during which subsequent events are
required to be considered. This period is between the balance sheet date and
when the financial statements are authorized for issue. Furthermore, disclosure
is required as to the date the financial statements were authorized for issue
and who provided that authorization.





Other
accounting standards issued by the CICA during the year ended December 31, 2004
are not expected to materially impact the Fund.





**Risk
Factors and Risk Management**





Enerplus
investors are participating in the net funds flow from a portfolio of western
Canadian crude oil and natural gas producing properties. As such, the funds 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:


****


**Commodity
Price Risk**





Enerplus’
operating results and financial condition are dependent on the prices we receive
for our crude oil and natural gas production. These prices may fluctuate widely
in response to a variety of factors including global and domestic economic
conditions, weather conditions, the supply and price of imported oil and
liquefied natural gas, the production and storage levels of North American
natural gas, political stability, transportation facilities, the price and
availability of alternative fuels and government regulations.





*We
use financial derivative instruments and other hedging mechanisms to help limit
the adverse effects of natural gas and oil price volatility. However, we do not
hedge all of our production and expect there will always be a portion that
remains unhedged. Furthermore, we use financial instruments such as collars and
three-way options that offer only limited protection within selected price
ranges. To the extent price exposure is hedged, we may forego the benefits that
would otherwise be experienced if commodity prices increase.*




**Operational
Risk and Cost Control**





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 may increase the risk of write-downs of our oil and
gas property investments. Regulatory changes to reserve reporting practices can
also result in reserve write-downs. As activity levels in the industry increase,
upward pressure is placed on administrative and operating costs. Higher costs
will decrease the amount of funds flow received by the Fund and therefore,
reduce distributions to unitholders.


**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **65**





*We
strive to acquire low risk, mature properties with a high proportion of proved
reserves, positive operating metrics, long reserve lives and predictable
production. Similarly, we generally participate in lower-risk development
projects, while farming out or monetizing higher risk exploratory
prospects.*





*Each
year, a firm of independent engineers evaluates a significant portion of our
proved and probable reserves. At December 31, 2004 approximately
88%* ****** *of
our major properties, representing proved plus probable net present value,
discounted at 10%, were evaluated. The remaining minor properties were evaluated
internally and reviewed by the independent engineers. The Reserves Committee of
the Board of Directors has reviewed and approved the reserve report of the
independent evaluators.*





*We
strive to control costs through incentive-based compensation plans that reward
employees for cost control and value-added initiatives. We attempt to minimize
costs by exploiting our purchasing strength with suppliers. In 2004, we fixed
the price on a portion of our Alberta electrical consumption. We use detailed
budgeting and accounting practices to monitor costs. Multi-functional teams
regularly perform integrated field reviews designed to reduce costs and increase
revenues from our properties.*





*Despite
these efforts, it can be difficult to control costs in the oil and gas industry,
especially in periods of high commodity prices when the demand for goods and
services is strong. Oil and gas production involves a significant amount of
fixed costs that are difficult to reduce without decreasing production. In
addition, approximately 40% of Enerplus’ production is operated by third
parties. We have limited ability to influence costs on partner-operated
properties.*




**Reserve
Risk**





Oil and
natural gas reserves naturally deplete as they are produced over time. Our
ability to replace production depends on our success in acquiring new reserves
and developing existing reserves. Acquisitions 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.





*Acquisitions
are subject to investment guidelines, due diligence and review. Major
acquisitions are approved by the Board of Directors and where appropriate,
independent reservoir engineer evaluations are obtained.*




**Non-Resident
Ownership and Mutual Fund Trust Status**





Since
our listing on the New York Stock Exchange in November of 2000, we have seen
increased trading volumes and levels of ownership by non-residents of Canada.
Based on information received from our transfer agent and financial
intermediaries in February 2005, an estimated 70% **** of our
outstanding trust units are held by non-residents. However, this estimate may
not be accurate as it is based on certain assumptions and data from the
securities industry that does not have a well-defined methodology to determine
the residency of beneficial holders of securities.





Enerplus
currently meets the requirements of a Mutual Fund Trust as defined in the Income
Tax Act (Canada). Our trust indenture does not have a specific limit on the
percentage of trust units that may be owned by non-residents. In March 2004, the
Canadian federal budget proposed an amendment that would impose non-resident
restrictions on Enerplus. The proposed amendment would have required Enerplus to
comply by 2007 with the requirement that it is “not to be maintained primarily
for the benefit of non-residents”.





In
response to submissions from and discussions with investors and the income trust
sector, the Canadian government withdrew this amendment from the budget
legislation in December 2004. In his letter to Enerplus, the Minister of Finance
stated “the representations from the energy sector have emphasized the
importance of non-resident investment in this area, as well as the practical
difficulties associated with reducing and controlling levels of non-resident
ownership in publicly traded funds.”





Although
the proposed amendment has been withdrawn, we understand the government
continues to study the issue with a view to ensuring the Canadian tax payable by
non-residents is appropriate. We expect the government will work closely with
industry in a consultative process. Although studies commissioned by the
Canadian Association of Income Funds have shown that non-resident tax leakage is
minimal in this regard, there are no guarantees that the government will come to
the same conclusion. There is a risk that the Canadian government may propose
further changes to the tax regime.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **66**







*Enerplus
will continue to work closely with industry associations, the investment
community and directly with politicians and the Department of Finance on this
issue.*




**Access
to Capital Markets**





Since
we distribute the majority of our net funds flow to unitholders, we must finance
a large portion of our acquisition and development activity within the equity
and debt capital markets. As such, we are dependent on continued access to the
capital markets to fund our activities directed toward maintaining and
increasing value for our unitholders.





*Enerplus
has listings on the Toronto and New York stock exchanges and maintains an active
investor relations program.*





*We
maintain a prudent capital structure by retaining a portion of funds flow for
capital spending and utilizing the equity markets when deemed
appropriate.*





*Continued
access to capital is dependant on our ability to maintain our track record of
performance and to demonstrate the advantages of the acquisition or development
program that we are financing at the time.*





**Environmental
and Safety Risk (“E&S”)**





Environmental
and safety risks influence the workforce, operating costs and the establishment
of regulatory standards.





*We
have established an EHS Management System designed to:*





•
    *provide
      staff with the training and resources needed to complete work safely and
      effectively;*•
    *incorporate
      hazard assessment and risk management as an integral part of everyday
      business;*•
    *monitor
      performance to ensure that our operations comply with legal obligations
      and the standards we set for ourselves; and*•
    *identify
      and manage environmental liabilities associated with our existing asset
      base and**potential
      acquisitions.*





*We have a site
inspections program and a corrosion risk management program designed to ensure
compliance with environmental laws and regulations. We carry insurance to cover
a portion of our property losses, liability and business interruption. EHS risks
are reviewed regularly by a committee of the Board of Directors.*





**Interest
Rate Exposure**





Enerplus has
exposure to movements in interest rates. Changing interest rates can affect
borrowing costs and the trust unit price of yield-based investments such as
Enerplus.





*We monitor the
interest rate forward market and have fixed the interest rate on approximately
24% of our debt through fixed rate senior unsecured notes and through interest
rate swaps for terms up to three years.*





**Foreign
Currency Exposure**





Enerplus has
exposure to fluctuations in foreign currency as a result of the issuance of
senior unsecured notes denominated in U.S. dollars.





We have hedged our
foreign currency exposure on US$175 million of senior unsecured notes using
financial swaps that convert the U.S. denominated debt to Canadian dollar debt
with Canadian dollar interest obligations. We have not hedged our foreign
exchange exposure with respect to the US$54 million of senior unsecured notes
issued in October 2003 which have U.S. dollar interest payment
obligations.





Enerplus also has
indirect exposure to fluctuations in foreign currency as crude oil sales and a
portion of our natural gas sales are based on U.S. dollar indices. Our oil and
gas revenues benefit from a weak Canadian dollar relative to the U.S.
dollar.





*We have not
entered into any foreign currency derivatives with respect to oil and natural
gas sales****.***





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **67**







****


**Counterparty
Risk**





We assume customer
credit risk associated with oil and gas sales, financial hedging transactions
and joint venture participants.





*We have
established credit policies and controls designed to mitigate the risk of
default or non-payment with respect to oil and gas sales, financial hedging
transactions and joint venture participants. We maintain a diversified sales
customer base and we review our single-entity exposure on a regular
basis.*





**Regulatory
Risk**





Government
royalties, income tax laws, environmental laws and regulatory requirements can
have a significant financial and operational impact on Enerplus. As an oil and
gas producer, we are subject to a broad range of regulatory requirements.
Similarly, as a mutual fund trust, we have a unique structure that is vulnerable
to changes in legislation or income tax law.





*Although we
have no control over these regulatory risks, we monitor changes in these areas
by participating in industry organizations and conferences, exchanging
information with third party experts and employing qualified individuals to
assess the impact of such changes on our financial and operating results.*





**Unitholder
Liability**





In the past, there
has been some concern that trust unitholders might be held personally liable for
the indebtedness of the Fund.





*Enerplus is
registered in Alberta, which passed legislation in June 2004 to provide
statutory protection for unitholders similar to the protection afforded
shareholders in a corporation. Two other provinces (Ontario and Quebec) also
have statutory protection for unitholders. Our bank credit agreement and our
debenture agreements do not allow the creditors to extend recourse to
unitholders beyond the unitholders’ equity investment in the
Fund.*





**Business
Prospects**





Enerplus offers
investors the benefits of owning a large, diversified portfolio of oil and
natural gas properties without significant exposure to the exploration risks
commonly associated with traditional exploration and production (“E&P”)
companies. As such, our business prospects are closely linked to the
opportunities and challenges associated with oil and natural gas production. In
particular, Enerplus is strongly influenced by the price of crude oil and
natural gas, both of which have been volatile in recent years.





In 2004, we
delivered a 21.5% total return to our Canadian unitholders and a 29.9% return to
our U.S. unitholders through unit appreciation and monthly cash distributions.
Furthermore, the average annual return to our unitholders over the last five
years has been 60.7%. Looking forward to 2005, our business plan features some
of the same strategies that have supported our 19-year track record of
success:





**Growth**





•
    replace
      production through a disciplined acquisition and development
      strategy;•
    focus
      on acquisitions where we have a competitive advantage;•
    focus
      on larger acquisitions to avoid the competition for smaller
      packages;•
    acquire
      properties with predictable production profiles, long reserve lives,
      positive operating metrics and opportunities for low risk development;•
    consider
      diversification into other energy-related investments;•
    maintain
      a portfolio of future development opportunities within existing
      properties;•
    maintain
      a work environment that attracts and retains qualified
      professionals;





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **68**







**Portfolio
Optimization**





•
    develop
      core competencies and focus our asset base where we have a competitive
      technical or operating advantage;•
    utilize
      technologies and expertise to optimize the performance of existing
      properties through low-risk development, production enhancements and cost
      management;•
    dispose
      of marginal non-core properties at attractive
  valuations;


****


**Risk
Management**





•
    hedge
      oil and natural gas prices on a portion of future production to provide
      protection in the event of adverse price movements;•
    hedge
      a portion of future electrical costs;•
    focus
      on low-risk development;





**Corporate
Governance**





•
    ensure
      compliance with the requirements of the TSX, the NYSE and the relevant
      Securities Administrators;•
    apply
      high standards of corporate governance and ethics;•
    apply
      standards and practices that protect the environment and the health and
      safety of our employees;





**Financing**





•
    utilize
      debt conservatively;•
    diversify
      credit sources and payment terms;•
    hedge
      interest rates associated with a portion of long-term
  debt;•
    withhold
      10% to 30% of funds flow from operations to contribute toward annual
      development expenditures;•
    issue
      equity for acquisitions and growth opportunities in a manner that adds
      value to existing unitholders.





**Summary
2005 Outlook**





The
following chart summarizes Enerplus’ 2005 outlook provided throughout this
MD&A. We do not attempt to forecast commodity prices, and as a result, we do
not forecast future cash distributions to unitholders. Readers are encouraged to
apply their own price expectations to the following factors to arrive at an
expected cash distribution.





Summary of
      2005 Expectations
    
    Target
    
    CommentsAverage
      annual production
    
    75,500
      BOE/day
    
    Assumes
      current disposition package and no new acquisitionsExit rate
      December 2005 production
    
    77,500
      BOE/dayCurrent
      disposition package
    
    2,500
      BOE/day
    
    Expected to
      close in the first quarter of 2005 with proceeds of $60
      millionAverage
      royalty rate
    
    20%
    
    Percentage of
      gross unhedged salesOperating
      expenses
    
    $7.45/BOEG&A
      costs
    
    $1.45/BOE
    
    Includes
      non-cash charges of $0.18/BOE (unit rights plan)Capital
      taxes
    
    $6
      million
    
    Based on
      current capital structureAverage
      interest cost
    
    4.0%
    
    Based on
      current fixed rates and forward marketPayout
      ratio
    
    70-90%Development
      capital spending
    
    $275
      million
    
    Based on
      current plans and price environmentDRIP equity
      issuance
    
    $10
      millionOil & gas
      price hedging
    
    continuing
    
    See Note 12
      to the financial statements for a list of current hedge
      positions





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **69**







**Additional
Information**





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





**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 affecting the economic performance of Enerplus.
Undue reliance should not be placed on these forward-looking statements which
are based upon management’s assumptions and are subject to 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. Enerplus undertakes no obligation to update publicly or revise any
forward-looking statements contained herein and such statements are expressly
qualified by the cautionary statement.





**ENERPLUS
      RESOURCES FUND 2004 ANNUAL REPORT**
    **70**