EXHIBIT 99.3

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Management's Discussion and Analysis ("MD&A")

The following discussion and analysis of financial results is dated February 24, 2010 and is to be read in conjunction with the audited consolidated
financial statements as at and for the years ended December 31, 2009 and 2008. All amounts are stated in Canadian dollars unless otherwise specified. All references to GAAP refer to Canadian
generally accepted accounting principles. All note references relate to the notes included with the consolidated financial statements. In accordance with Canadian practice revenues are reported on a
gross basis, before deduction of Crown and other royalties, unless otherwise stated. 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.

The
following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under "Forward-Looking Information and Statements" for our disclaimer on forward-looking
information and statements.

NON-GAAP MEASURES

Throughout the MD&A we use the term "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity. We calculate payout
ratio by dividing cash distributions to unitholders ("cash distributions") by cash flow from operating activities ("cash flow"), both of which appear on our consolidated statements of cash flows
prepared in accordance with GAAP. "Adjusted payout ratio" is calculated as cash distributions plus development capital and office expenditures divided by cash flow. The terms "payout ratio" and
"adjusted payout ratio" do not have a standardized meaning or definition as prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other entities. Refer to
the Liquidity and Capital Resources section of the MD&A for further information.

OVERVIEW

Early in 2009 in response to the steep decline in commodity prices and the global credit crisis we lowered our monthly distributions to $0.18 per unit and
significantly reduced our development capital program. This was done to ensure we maintained a strong balance sheet to provide the financial flexibility and liquidity to pursue growth assets.

In
June 2009 we successfully diversified our credit sources through a private placement of senior unsecured notes that raised gross proceeds of approximately $338.7 million. At
December 31, 2009 our entire $1.4 billion credit facility was undrawn and our trailing debt to cash flow ratio was 0.6x.

Throughout
2009 we executed on our strategy of acquiring new positions in earlier stage resource plays. On September 1, 2009 we acquired an average 21.5% working interest in approximately
540,000 gross acres of land in the U.S. Marcellus shale gas play. Total consideration was US$411 million comprised of US$164.4 million of cash paid on closing and
US$246.6 million to be paid over time as a carry representing 50% of our partners' future drilling and completion costs. In conjunction with the acquisition we completed an equity offering on
September 9, 2009 raising gross proceeds of $225.3 million through the issuance of 10.4 million trust units. We also acquired additional Bakken land interests in southeast
Saskatchewan and North Dakota for approximately $55 million during 2009.

Our
operational results for 2009 were generally in-line with guidance. We exited the year with production of 85,400 BOE/day, which was slightly lower than our expectations due to
extreme cold weather and downtime at two facilities. Operating costs were better than expected along with G&A costs before one-time charges.

In
late 2009 we announced our intention to sell approximately 14,000 BOE/day of non-core production that does not fit with our strategy going forward. This should provide additional
funds for acquisitions and capital spending during 2010, and allow us to focus our efforts on high impact properties.

We
expect to take advantage of SIFT conversion rules which will allow us to significantly simplify our organizational structure at the same time as we convert to a dividend paying corporation.
Assuming the conversion proposal receives Board approval and unitholder acceptance, we expect to convert into a corporation on or about January 1, 2011.

4      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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RESULTS OF OPERATIONS

Production

Production during 2009 averaged 91,569 BOE/day, slightly ahead of our guidance of 91,000 BOE/day and 4% lower than 95,687 BOE/day in 2008.
The decrease compared to 2008 was consistent with our expectations as reduced capital spending did not completely replace natural reservoir declines during the year.

Average
production in 2009 was weighted 59% to natural gas and 41% to crude oil and liquids on a BOE basis. Average production volumes for the years ended December 31, 2009 and 2008 are
outlined below:

|Daily Production Volumes       |  | 2009    |  |  | 2008    |  | % Change | 
|------------------------------ |  | ------- |  |  | ------- |  | -------- | 
|                               |  |        
|Natural gas (Mcf/day)          |  | 326,570 |  |  | 338,869 |  | (4)%     | 
|Crude oil (bbls/day)           |  | 32,984  |  |  | 34,581  |  | (5)%     | 
|Natural gas liquids (bbls/day) |  | 4,157   |  |  | 4,627   |  | (10)%    | 
|Total daily sales (BOE/day)    |  | 91,569  |  |  | 95,687  |  | (4)%     | 
|                               |  |        

Our average daily production for the month of December was approximately 85,400 BOE/day, below our anticipated exit rate of 88,000 BOE/day. During
the month of December we experienced interruptions of 1,300 BOE/day due to weather freeze-ups, 500 BOE/day due to unscheduled downtime at non-operated facilities,
and the delay of approximately 800 BOE/day due to the timing of capital projects.

Considering
our development capital program for the year, we expect 2010 production volumes to average 86,000 BOE/day, weighted 58% to natural gas and 42% to crude oil and liquids. We expect
our production volumes to increase throughout the year and to exit 2010 at approximately 88,000 BOE/day which does not contemplate any potential acquisitions or dispositions.

Pricing

The prices received for our natural gas and crude oil production directly impact our earnings, cash flow and financial condition. The following table compares
our average selling prices for 2009 with those of 2008. It also compares the benchmark price indices for the same periods.

|Average Selling Price(1)      |  |   | 2009  |  |  |   | 2008  |  | % Change | 
|----------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                              |  |  
|Natural gas (per Mcf)         |  | $ | 3.91  |  |  | $ | 8.17  |  | (52)%    | 
|Crude oil (per bbl)           |  | $ | 58.54 |  |  | $ | 91.31 |  | (36)%    | 
|Natural gas liquids (per bbl) |  | $ | 41.54 |  |  | $ | 68.93 |  | (40)%    | 
|Per BOE                       |  | $ | 36.89 |  |  | $ | 65.79 |  | (44)%    | 
|                              |  |  

|Average Benchmark Pricing                                         |  |   | 2009  |  |  |   | 2008   |  | % Change | 
|----------------------------------------------------------------- |  | - | ----- |  |  | - | ------ |  | -------- | 
|                                                                  |  |  
|AECO natural gas  monthly index (CDN$/Mcf)                       |  | $ | 4.14  |  |  | $ | 8.13   |  | (49)%    | 
|AECO natural gas  daily index (CDN$/Mcf)                         |  | $ | 3.95  |  |  | $ | 8.14   |  | (51)%    | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                   |  | $ | 4.03  |  |  | $ | 8.93   |  | (55)%    | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf) |  | $ | 4.58  |  |  | $ | 9.50   |  | (52)%    | 
|WTI crude oil (US$/bbl)                                           |  | $ | 61.80 |  |  | $ | 99.65  |  | (38)%    | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                         |  | $ | 70.23 |  |  | $ | 106.01 |  | (34)%    | 
|CDN$/US$ exchange rate                                            |  |   | 0.88  |  |  |   | 0.94   |  | (6)%     | 
|                                                                  |  |  

Natural Gas

Natural gas prices declined through the first three quarters of 2009, opening at $6.67/Mcf at AECO and falling to a daily low of $2.03/Mcf on September 3,
2009. The weakening natural gas price was due to demand destruction from the sluggish economy and also an over supply from US domestic natural gas production. Storage inventories grew to record levels
as demand for cooling through the summer was low due to mild weather. Minimal disruptions from hurricane activity kept supply strong causing additional downward pressure on price. By October, gas
prices started to recover with the onset of winter weather and lower storage injection rates ending the year at $5.68/Mcf.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY5

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During
2009 we sold approximately 90% of our natural gas on the AECO index split evenly between the daily and monthly indices and the remaining 10% against monthly U.S. based indices. During
2009 we sold our natural gas for an average price of $3.91/Mcf (net of transportation costs), a decrease of 52% from $8.17/Mcf realized in 2008. This decrease is comparable to the price
decreases realized in the AECO daily and monthly indices and the NYMEX monthly index.

Monthly Natural Gas Prices

GRAPHIC

Crude Oil

Crude oil prices increased throughout 2009 from the low levels reached at the start of the year caused by the global economic crisis. The West Texas Intermediate
("WTI") crude oil benchmark price reached a low of US$33.98/bbl in mid February only to recover and reach a high of US$81.37/bbl in October. Successful OPEC production cuts along with stabilization of
the economy supported the oil price recovery. In the fourth quarter of 2009 prices remained between US$70/bbl and US$80/bbl. The industry, however, continues to be challenged by weak
fundamentals with inventories remaining at record high levels. At year-end, oil managed to rally in response to a weaker U.S. dollar and strength in U.S. equity markets, closing at
US$79.36/bbl.

Our
crude oil production in 2009 was weighted 72% light/medium and 28% heavy. The average price received for our crude oil (net of transportation costs) was $58.54/bbl during 2009, a 36%
decrease over 2008. The WTI price, after adjusting for the change in the U.S. dollar exchange rate, decreased 34% year-over-year. Heavy oil differentials were narrow
throughout the year as recent refinery conversions increased demand for heavy oil in anticipation of higher oil sands output. However, realized prices on our light oil were negatively impacted by
reduced refinery demand for light oil.

Monthly Crude Oil Prices

GRAPHIC

6      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Foreign Exchange

The Canadian dollar opened 2009 at a CDN$/US$ exchange rate of $0.83 and strengthened throughout most of the year hitting a high in October of $0.97 and ending
the year at $0.96. The Canadian dollar strengthened against the U.S. dollar during 2009 but was weaker on average compared to 2008. As most of our crude oil and natural gas is priced in
reference to U.S. dollar denominated benchmarks, a weaker Canadian dollar increases the prices that we would have otherwise realized.

Price Risk Management

We continue to adjust our price risk management program with consideration given to our overall financial position together with the economics of our development
capital program and potential acquisitions. Consideration is also given to the costs of our risk management program as we seek to limit our exposure to price downturns.

We
have entered into additional commodity contracts during and subsequent to the fourth quarter of 2009 to protect a larger portion of our cash flow during 2010. Including all financial contracts
transacted as of February 16, 2010, we have approximately 39% of our expected 2010 natural gas production, net of royalties, hedged at an effective price of $6.45/Mcf and approximately 43% of
our expected 2010 crude oil production hedged at an effective price of US$77.69/bbl. We have also hedged a portion of our electricity consumption through December 2011 to protect against rising
electricity costs in the Alberta power market. See Note 11 for a detailed list of our current price risk management positions.

The
following is a summary of the financial contracts in place at February 16, 2010 expressed as a percentage of our forecasted net production volumes:

|                                         |  | Natural Gas (CDN$/Mcf) |                                  | Crude Oil (US$/bbl)
|---------------------------------------- |  | ---------------------- | -------------------------------- | -------------------
|                                         |  |                        | January 1,
2010 
March 31,
2010 |                    
|                                         |  |                       
|Purchase Puts (floor prices)             |  | $                      | 7.89                             |                    
|%                                        |  |                        | 14%                              |                    
|Sold Puts (limiting downside protection) |  | $                      | 3.96                             |                    
|%                                        |  |                        | 4%                               |                    
|Swaps (fixed price)                      |  | $                      | 7.33                             |                    
|%                                        |  |                        | 11%                              |                    
|Sold Calls (capped price)                |  | $                      | 12.13                            |                    
|%                                        |  |                        | 2%                               |                    
|Purchased Calls (repurchasing upside)    |  | $                      |                                 |                    
|%                                        |  |                        |                                 |                    
|                                         |  |                       

Accounting for Price Risk Management

During 2009 our price risk management program generated cash gains of $74.8 million on our natural gas contracts and $81.0 million on our crude oil
contracts. In comparison, in 2008 we experienced cash losses of $20.1 million and $83.1 million respectively. The cash gains are a result of our floor protection which helped to offset
the decline in commodity prices.

As
the forward markets for natural gas and crude oil fluctuate, new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash
charge or gain to earnings. At December 31, 2009 the fair value of our natural gas and crude oil derivative instruments, net of premiums, represented a gain of $20.4 million and loss of
$20.3 million respectively. The gain is recorded as a current deferred financial asset and the loss is recorded as a current deferred financial liability on our balance sheet. In comparison, at
December 31, 2008 the fair value of our natural gas and crude oil derivative instruments represented gains of $24.3 million and $96.6 million

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY7

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respectively.
The change in the fair value of our commodity derivative instruments during 2009 resulted in unrealized losses of $3.9 million for natural gas and $117.0 million for crude
oil. See Note 11 for details.

The
following table summarizes the effects of our financial contracts on income for the years ended December 31, 2009 and 2008.

|Risk Management Costs($ millions, except per unit amounts) |                                    |   | 2009   |        |   |            | 2008       | 
|---------------------------------------------------------- | ---------------------------------- | - | ------ | ------ | - | ---------- | ---------- | 
|                                                           |                                    |  
|Cash gains/(losses):                                       |                                    |   |        |        |   |            |            | 
|                                                           | Natural gas                        |   | $      | 74.8   |   | $          | 0.63/Mcf   | 
|                                                           | Crude oil                          |   |        | 81.0   |   | $          | 6.73/bbl   | 
|                                                           |                                    |   |        |        |   |            |            | 
|Total cash gains/(losses)                                  |                                    | $ | 155.8  |        | $ | 4.66/BOE   |            | 
|Non-cash gains/(losses) on financial contracts:            |                                    |   |        |        |   |            |            | 
|                                                           | Change in fair value  natural gas |   | $      | (3.9   | ) | $          | (0.03)/Mcf | 
|                                                           | Change in fair value  crude oil   |   |        | (117.0 | ) | $          | (9.72)/bbl | 
|                                                           |                                    |   |        |        |   |            |            | 
|Total non-cash gains/(losses)                              |                                    | $ | (120.9 | )      | $ | (3.62)/BOE |            | 
|                                                           |                                    |   |        |        |   |            |            | 
|Total gains                                                |                                    | $ | 34.9   |        | $ | 1.04/BOE   |            | 
|                                                           |                                    |  

Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts as listed in Note 11 and are based on forward markets as at February 16, 2010. To
the extent the market price of crude oil and natural gas change significantly from current levels, the sensitivities will no longer be relevant as the effect of our commodity contracts
will change.

|Sensitivity Table                                          |  |   | Estimated
Effect on 2010
Cash Flow
per Trust Unit(1) | 
|---------------------------------------------------------- |  | - | ---------------------------------------------------- | 
|                                                          
|Change of $0.50 per Mcf in the price of AECO natural gas   |  | $ | 0.12                                                 | 
|Change of US$5.00 per barrel in the price of WTI crude oil |  | $ | 0.14                                                 | 
|Change of 1,000 BOE/day in production                      |  | $ | 0.07                                                 | 
|Change of $0.01 in the US$/CDN$ exchange rate              |  | $ | 0.06                                                 | 
|Change of 1% in interest rate                              |  | $ | 0.01                                                 | 
|                                                          

The
impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors.

Revenues

Crude oil and natural gas revenues in 2009 were $1,232.8 million ($1,259.2 million, net of $26.4 million of transportation costs), a
decrease of 46% compared to $2,304.2 million ($2,331.9 million, net of $27.7 million of transportation costs) during 2008. The majority of this decrease was due to the significant
decline in commodity prices combined with slightly lower production levels.

|Analysis of Sales Revenue(1)($ millions) |  |   | Crude Oil |   |   | NGLs  |   |   | Natural Gas |   |   | Total   |   | 
|---------------------------------------- |  | - | --------- | - | - | ----- | - | - | ----------- | - | - | ------- | - | 
|                                        
|2008 Sales Revenue                       |  | $ | 1,155.7   |   | $ | 116.7 |   | $ | 1,031.8     |   | $ | 2,304.2 |   | 
|Price variance(1)                        |  |   | (394.5    | ) |   | (41.5 | ) |   | (527.4      | ) |   | (963.4  | ) | 
|Volume variance                          |  |   | (56.4     | ) |   | (12.2 | ) |   | (39.4       | ) |   | (108.0  | ) | 
|                                        
|2009 Sales Revenue                       |  | $ | 704.8     |   | $ | 63.0  |   | $ | 465.0       |   | $ | 1,232.8 |   | 
|                                        

Other Income and Expenses

During 2009 we recorded other expenses of $1.5 million compared to other income of $8.5 million in 2008. We realized a loss of $2.2 million
on the sale of marketable securities during 2009. In 2008 we realized a net loss of $1.7 million related to our marketable securities which was offset by $8.9 million in insurance
proceeds.

8      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Total royalties paid during 2009 decreased to $207.5 million
from $429.9 million in 2008, primarily due to lower commodity prices and to a lesser extent lower production volumes. As a percentage of oil and gas sales, net of transportation costs,
royalties in 2009 decreased to approximately 17% from 19% in the previous year largely due to Alberta's New Royalty Framework's sensitivity to lower natural gas prices in 2009.

The
province of Alberta is currently conducting a review of its royalty structure, to ensure the competitiveness of oil and gas investment in Alberta. The results of the review are expected to be
announced in the second or third quarter of 2010. Approximately 60% of our production is from Alberta.

Operating Expenses

Operating expenses during 2009 were $327.2 million, 2% lower than 2008 operating costs of $332.6 million due to lower power costs. On a BOE basis,
2009 operating expenses were $9.79/BOE or 3% higher than 2008 operating costs of $9.50/BOE due to lower production volumes during 2009.

For
2010 we expect operating costs to average $10.90/BOE. We are anticipating a modest increase in our power and labour costs, but expect other operating costs to remain essentially flat. Operating
costs are expected to be higher on a BOE basis due to lower average production.

General and Administrative Expenses ("G&A")

G&A expenses were $2.64/BOE or $88.3 million during 2009, approximately 8% higher than our guidance of $2.45/BOE and 40% higher than $1.88/BOE in 2008.
Our 2009 G&A expenses included one-time costs of $11.1 million ($0.33/BOE) associated with recent staff reductions and transaction costs related to our senior notes issue.

Cash
G&A expenses before one-time items were $70.7 million or $12.0 million higher than 2008 due to increased technical staff, higher office lease costs along with the impact
of lower overhead recoveries in 2009 resulting from our reduced capital program.

Non-cash
G&A expenses relate solely to our trust unit rights incentive plan which were $6.5 million or $0.20/BOE compared to $7.0 million or $0.20/BOE for 2008. These amounts
are based on the fair value of the rights which are determined on the grant date using a binomial lattice option-pricing model and may not represent the amount realized by employees. See Note 9
for further details.

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

|General and Administrative Costs($ millions) |  |   | 2009 |  |  |   | 2008 | 
|-------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                             |  |  
|Cash, before one-time items                  |  | $ | 70.7 |  |  | $ | 58.7 | 
|One-time items                               |  |   | 11.1 |  |  |   |     | 
|Trust unit rights incentive plan (non-cash)  |  |   | 6.5  |  |  |   | 7.0  | 
|                                             |  |  
|Total G&A                                    |  | $ | 88.3 |  |  | $ | 65.7 | 
|                                             |  |  

|
|

|(Per BOE)                                   |  |   | 2009 |  |  |   | 2008 | 
|------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                            |  |  
|Cash, before one-time items                 |  | $ | 2.11 |  |  | $ | 1.68 | 
|One-time items                              |  |   | 0.33 |  |  |   |     | 
|Trust unit rights incentive plan (non-cash) |  |   | 0.20 |  |  |   | 0.20 | 
|                                            |  |  
|Total G&A                                   |  | $ | 2.64 |  |  | $ | 1.88 | 
|                                            |  |  

We expect total G&A expenses in 2010 to be $2.45/BOE including non-cash G&A costs of approximately $0.20/BOE. We expect to reduce our Canadian G&A
costs however we anticipate some increases in our U.S. operations as activity levels increase with the development of our Marcellus and North Dakota assets.

In
addition, we expect to incur approximately $3 million or $0.10/BOE to simplify our underlying organizational structure and facilitate the conversion from a trust to a corporation. These
costs will be reported separately from G&A expenses.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY9

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Interest Expense

Interest expense includes interest on long-term debt, the premium amortization on our US$175 million senior unsecured notes, unrealized gains
and losses resulting from the change in fair value of our interest rate swaps as well as the interest component on our cross currency interest rate swap ("CCIRS"). See Note 7 for further
details.

Interest
on long-term debt during 2009 totaled $30.6 million, a $12.0 million decrease from $42.6 million in 2008. This decrease is due to lower average indebtedness
year-over-year. During 2009 our weighted average interest rate was 4.2% compared to 3.8% in 2008.

For
the year ended December 31, 2009 non-cash interest losses were $25.7 million compared to non-cash gains of $18.4 million in 2008. The changes in the
fair value of our interest rate swaps and the interest component on our CCIRS cause non-cash interest to fluctuate between periods.

The
following table summarizes the cash and non-cash interest expense:

|Interest Expense($ millions)  |  |   | 2009 |  |  |   | 2008  |   | 
|----------------------------- |  | - | ---- |  |  | - | ----- | - | 
|                              |  |  
|Interest on long-term debt    |  | $ | 30.6 |  |  | $ | 42.6  |   | 
|Non-cash interest loss/(gain) |  |   | 25.7 |  |  |   | (18.4 | ) | 
|                              |  |  
|Total Interest Expense        |  | $ | 56.3 |  |  | $ | 24.2  |   | 
|                              |  |  

As a result of the additional senior unsecured notes issued on June 18, 2009, approximately 77% of our debt was based on fixed interest rates while 23%
had floating interest rates at December 31, 2009. In comparison, at December 31, 2008 approximately 28% of our debt was based on fixed interest rates and 72% was floating.

Foreign Exchange

During the year we recorded foreign exchange gains of $59.6 million compared to losses of $25.9 million in 2008. Unrealized gains on the
translation of our U.S. dollar denominated senior notes accounted for the majority of the gain in 2009. See Note 8 for further details.

Capital Expenditures

Development Capital Spending

During 2009 our development capital spending totaled $299.1 million, net of Alberta Drilling Royalty Credits ("DRC") of $21.7 million. This
represents a $278.6 million or 48% decrease from 2008 spending levels, reflecting a more conservative development capital program given the downturn in commodity prices. In comparison to our
guidance, our 2009 spending was approximately $15.9 million below our estimate of $315 million. Approximately half of this shortfall relates to conventional oil and gas projects that
were delayed into 2010 due to the extreme cold weather conditions in December. The remaining difference arose from our Marcellus shale gas play as we experienced some completion delays due to service
rig crew availability and our fourth drilling rig arriving later than anticipated.

Our
spending increased in the fourth quarter with a significant amount being directed towards our shallow gas properties due to the support of the DRC program. During 2009 we drilled 24 net oil
wells and 289 net natural gas wells, achieving an overall success rate of 99%.

Property Acquisitions and Dispositions

Property acquisitions totaled $272.0 million during 2009 compared to $15.3 million in 2008. We had three property acquisitions during 2009 that
accounted for the majority of the spending.

During
the second quarter of 2009 we acquired approximately 200 BOE/day of non-operated Bakken production including 11 net sections of land in southeast Saskatchewan for
approximately $25 million.

On
September 1, 2009 we acquired an average 21.5% non-operated working interest in approximately 540,000 gross acres in the Marcellus shale gas play in the northeast
United States. Total consideration for the acquisition was US$411 million, comprised of US$164.4 million in cash that was paid upon closing and US$246.6 million to be paid
over time as a carry of 50% of the operator's future drilling and completion costs. We expect this carry will be spent over the next four years and it will be reported as property acquisitions as it
is incurred. At December 31, 2009 our remaining Marcellus carry commitment was US$237.3 million after considering 2009 spending as well as final closing adjustments.

10      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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On October 27, 2009 we acquired additional Bakken land interests in North Dakota for approximately US$27 million, consisting of cash consideration of US$15 million and
US$12 million to be paid within one year representing a carry commitment of 100% of our partners drilling and completion costs. Since the carry commitment is due in full within one year of the
acquisition date regardless of actual spending, we have recorded the entire US$27 million acquisition during 2009. At December 31, 2009 our remaining carry balance of
US$9.6 million was recorded as a liability on our balance sheet.

Property
dispositions during 2009 were $104.3 million compared to $504.8 million in 2008. Our 2009 divestments relate mainly to the sale of a non-core oil property in Western
Canada with production of approximately 200 BOE/day for proceeds of $101 million. Our 2008 divestments relate mainly to the $502.0 million disposition of our
non-operated Joslyn oil sands property.

Corporate Acquisitions

Corporate acquisitions during 2008 totaling approximately $1.7 billion relate to the acquisition of Focus Energy Trust that closed on
February 13, 2008.

|Capital Expenditures($ millions)                   |  |   | 2009   |   |  |  |   | 2008    |   | 
|-------------------------------------------------- |  | - | ------ | - |  |  | - | ------- | - | 
|                                                   |  |  
|Development expenditures                           |  | $ | 231.8  |   |  |  | $ | 442.4   |   | 
|Plant and facilities                               |  |   | 67.3   |   |  |  |   | 135.3   |   | 
|                                                   |  |  
|Development Capital                                |  |   | 299.1  |   |  |  |   | 577.7   |   | 
|Office                                             |  |   | 6.7    |   |  |  |   | 10.6    |   | 
|                                                   |  |  
|Sub-total                                          |  |   | 305.8  |   |  |  |   | 588.3   |   | 
|Property acquisitions(1)                           |  |   | 272.0  |   |  |  |   | 15.3    |   | 
|Corporate acquisitions                             |  |   |       |   |  |  |   | 1,757.5 |   | 
|Property dispositions(1)                           |  |   | (104.3 | ) |  |  |   | (504.8  | ) | 
|                                                   |  |  
|Total Net Capital Expenditures                     |  | $ | 473.5  |   |  |  | $ | 1,856.3 |   | 
|                                                   |  |  
|Capital Expenditures financed with cash flow       |  | $ | 407.6  |   |  |  | $ | 476.7   |   | 
|Capital Expenditures financed with debt and equity |  |   | 170.2  |   |  |  |   | 1,884.4 |   | 
|Proceeds received on property dispositions         |  |   | (104.3 | ) |  |  |   | (504.8  | ) | 
|                                                   |  |  
|Total Net Capital Expenditures                     |  | $ | 473.5  |   |  |  | $ | 1,856.3 |   | 
|                                                   |  |  

The following is a summary by play type of our development capital expenditures during 2009 (net of DRC credits) and 2008, as well as our expectations for
2010 (net of DRC credits).

|Play type($ millions)          |  |   | 2010 Estimate |  |   | 2009  |  |  |   | 2008  | 
|------------------------------ |  | - | ------------- |  | - | ----- |  |  | - | ----- | 
|                               |  |  
|Shallow Gas                    |  | $ | 41.0          |  | $ | 61.2  |  |  | $ | 159.1 | 
|Crude Oil Waterfloods          |  |   | 96.0          |  |   | 37.1  |  |  |   | 84.0  | 
|Tight Gas                      |  |   | 56.0          |  |   | 95.0  |  |  |   | 81.0  | 
|Bakken/Tight Oil               |  |   | 117.0         |  |   | 49.2  |  |  |   | 99.0  | 
|Other Conventional Oil and Gas |  |   | 35.0          |  |   | 29.7  |  |  |   | 103.4 | 
|Shale Gas                      |  |   | 80.0          |  |   | 12.3  |  |  |   |      | 
|Oil Sands                      |  |   |              |  |   | 14.6  |  |  |   | 51.2  | 
|                               |  |  
|Total                          |  | $ | 425.0         |  | $ | 299.1 |  |  | $ | 577.7 | 
|                               |  |  

We expect development capital expenditures in 2010 will be approximately $425 million (net of DRC credits of $33 million), including
approximately $125 million on assessment of early stage opportunities including land acquisitions, seismic and wells. We also expect our Marcellus carry spending will be approximately
$64 million which will be recorded as a property acquisition as it is considered part of the original acquisition cost.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY11

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Oil Sands

Our current oil sands portfolio includes our 100% owned and operated Kirby steam assisted gravity drainage ("SAGD") project and an 11% minority equity ownership
interest in Laricina Energy Ltd., a private oil sands company focused on SAGD development in the Athabasca oil sands. On April 17, 2009 we announced the deferral of further development
of the Kirby project although we expect to receive regulatory approval in 2010.

Our
oil sands projects have not commenced commercial production and as a result, all associated costs inclusive of acquisition expenditures are capitalized and excluded from our depletion calculation.
At December 31, 2009 capitalized costs life-to-date for our oil sands projects were $273.0 million compared to $257.6 million at
December 31, 2008.

Depletion, Depreciation, Amortization and Accretion ("DDA&A")

DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For 2009
DDA&A was $650.4 million or $19.45/BOE compared to $640.4 million or $18.29/BOE in 2008. The increase in our 2009 DDA&A is attributable to a higher depletion rate due to negative reserve
revisions at December 31, 2009.

No
impairment of the Fund's PP&E values existed at December 31, 2009 using year-end reserves and management's estimates of future prices. Our future price estimates are more fully
discussed in Note 3.

Goodwill

The goodwill balance of $607.4 million is a result of previous corporate acquisitions and represents the excess of the total purchase price over the fair
value of the net identifiable assets and liabilities acquired. The goodwill balance with respect to our U.S operations is exposed to foreign currency fluctuations as it is translated into Canadian
dollars at the period end exchange rate. No goodwill impairment existed as of December 31, 2009.

Asset Retirement Obligations

In connection with our operations, we anticipate we will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Total
future asset retirement obligations included on our balance sheet are estimated by management based on our net ownership interest in wells and facilities, estimated costs to abandon and reclaim the
wells and facilities and the estimated timing of the costs to be incurred in future periods. We have estimated the net present value of our total asset retirement obligations to be approximately
$230.5 million at December 31, 2009 compared to $207.4 million at December 31, 2008. The majority of the $23.1 million increase was due to the acceleration of the
timing of future abandonment and reclamation expenditures on the majority of our shallow gas properties due to the reduced economic life of our reserves that resulted from our December 31, 2009
reserve revisions.

Actual
asset retirement costs are incurred at different times compared to the recording of amortization and accretion charges. Actual asset retirement costs will be incurred over the next
66 years with the majority between 2030 and 2049. For accounting purposes, the asset retirement cost is amortized using a unit-of-production method based on proved
reserves before royalties, while the asset retirement obligation accretes until the time the obligation is settled.

Taxes

Future Income Taxes

Future income taxes arise from differences between the accounting and tax basis of assets and liabilities. A portion of the future income tax liability recorded
on the balance sheet will be recovered through earnings before 2011. The balance will be realized when future income tax assets and liabilities are realized or settled.

The
future income tax recovery for 2009 was $93.2 million compared to $51.2 million in 2008. The increase in the future income tax recovery was a result of lower net income in our
operating entities during 2009 compared to 2008 and the enactment of provincial SIFT legislation.

Current Income Taxes

In our current structure, payments are made between the operating entities and the Fund, which ultimately transfers both income and future income tax liability
to our unitholders. As a result minimal cash income taxes are generally paid by our Canadian operating entities. Effective

12      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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January 1,
2011 we would be subject to the SIFT tax should we remain a trust however we expect to convert to a corporation on or about January 1, 2011 and will be subject to normal
Canadian corporate taxes.

During
2009 our U.S. operations incurred current taxes in the amount of $0.2 million compared to $47.8 million in 2008. The decrease is due to lower net income combined with an
increase in capital expenditures for the year. The amount of current taxes recorded throughout the year on our U.S. operations is dependent upon the timing of both capital expenditures and
repatriation of funds to Canada. We expect current income and withholding taxes to average approximately 5% of cash flow from U.S. operations in 2010.

Tax Pools

We estimate our tax pools at December 31, 2009 to be as follows:

|Pool Type($ millions) |  |   | Trust |  |   | Operating
entities |  |   | Total | 
|--------------------- |  | - | ----- |  | - | ------------------ |  | - | ----- | 
|                     
|COGPE                 |  | $ | 467   |  | $ | 164                |  | $ | 631   | 
|CDE                   |  |   |      |  |   | 524                |  |   | 524   | 
|UCC                   |  |   |      |  |   | 630                |  |   | 630   | 
|CEE                   |  |   |      |  |   | 154                |  |   | 154   | 
|Tax losses and other  |  |   | 17    |  |   | 514                |  |   | 531   | 
|Foreign tax pools     |  |   |      |  |   | 412                |  |   | 412   | 
|                     
|Total                 |  | $ | 484   |  | $ | 2,398              |  | $ | 2,882 | 
|                     

Net Income

Net income in 2009 was $89.1 million or $0.53 per trust unit compared to $888.9 million or $5.54 per trust unit in 2008. The $799.8 million
decrease in net income was primarily due to a $1,071.5 million decrease in oil and gas sales (net of transportation costs) partially offset by decreased royalty expense of
$222.5 million, increased foreign exchange gains of $85.4 million and increased future income tax recoveries of $42.0 million.

Cash Flow from Operating Activities

Cash flow from operating activities in 2009 was $775.8 million or $4.58 per trust unit compared to $1,262.8 million or $7.86 per trust unit in
2008. The decrease is primarily due to decreased commodity prices and lower production volumes.

Selected Financial Results

|                                                                |  | Year ended December 31, 2009 |                     | Year ended December 31, 2008
|--------------------------------------------------------------- |  | ---------------------------- | ------------------- | ----------------------------
|Per BOE of production (6:1)                                     |  |                              | Operating
Cash
Flow | (1)                         
|                                                                |  |                             
|Production per day                                              |  |                              |                     |                             
|                                                                |  |                             
|Weighted average sales price(2)                                 |  | $                            | 36.89               |                             
|Royalties                                                       |  |                              | (6.21               | )                           
|Commodity derivative instruments                                |  |                              | 4.66                |                             
|Operating costs                                                 |  |                              | (9.71               | )                           
|General and administrative                                      |  |                              | (2.44               | )                           
|Interest expense, net of interest income & other income/expense |  |                              | (0.89               | )                           
|Foreign exchange gain/(loss)                                    |  |                              | 0.55                |                             
|Current income tax                                              |  |                              | (0.01               | )                           
|Restoration and abandonment cash costs                          |  |                              | (0.41               | )                           
|Depletion, depreciation, amortization and accretion             |  |                              |                    |                             
|Future income tax (expense)/recovery                            |  |                              |                    |                             
|                                                                |  |                             
|Total per BOE                                                   |  | $                            | 22.43               |                             
|                                                                |  |                             

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY13

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Selected Annual Canadian and U.S. Financial Results

The following table provides a geographical analysis of key operating and financial results for 2009 and 2008.

|                                         |                                                     | Year ended December 31, 2009 |        | Year ended December 31, 2008
|---------------------------------------- | --------------------------------------------------- | ---------------------------- | ------ | ----------------------------
|(CDN$ millions, except per unit amounts) |                                                     |                              | Canada |                             
|                                         |                                                     |                             
|Average Daily Production Volumes         |                                                     |                              |        |                             
|                                         | Natural gas (Mcf/day)                               |                              |        | 312,846                     
|                                         | Crude oil (bbls/day)                                |                              |        | 24,800                      
|                                         | Natural gas liquids (bbls/day)                      |                              |        | 4,157                       
|                                         | Total daily sales (BOE/day)                         |                              |        | 81,098                      
|Pricing(1)                               |                                                     |                              |        |                             
|                                         | Natural gas (per Mcf)                               |                              | $      | 3.86                        
|                                         | Crude oil (per bbl)                                 |                              | $      | 58.59                       
|                                         | Natural gas liquids (per bbl)                       |                              | $      | 41.54                       
|Capital Expenditures                     |                                                     |                              |        |                             
|                                         | Development capital and office                      |                              | $      | 258.4                       
|                                         | Acquisitions of oil and gas properties              |                              | $      | 34.5                        
|                                         | Corporate acquisitions                              |                              | $      |                            
|                                         | Dispositions of oil and gas properties              |                              | $      | (104.3                      
|Revenues                                 |                                                     |                              |        |                             
|                                         | Oil and gas sales(1)                                |                              | $      | 1,032.7                     
|                                         | Royalties                                           |                              | $      | (161.9                      
|                                         | Commodity derivative instruments gain/(loss)        |                              | $      | 34.9                        
|Expenses                                 |                                                     |                              |        |                             
|                                         | Operating                                           |                              | $      | 313.0                       
|                                         | General and administrative                          |                              | $      | 81.1                        
|                                         | Depletion, depreciation, amortization and accretion |                              | $      | 567.2                       
|                                         | Current income taxes (recovery)/expense             |                              | $      |                            
|                                         |                                                     |                             

Three Year Summary of Key Measures

Crude oil and natural gas sales increased to mid-2008 due to increased commodity prices and increased production from the Focus acquisition. Oil and
natural gas sales decreased in the latter part of 2008 with the sharp decline in commodity prices and were flat during 2009 as rising crude oil prices have largely been offset by declining natural gas
prices. Our reduced production levels in 2009 have also put downward pressure on oil and gas sales.

14      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Net
income has been affected by fluctuating commodity prices and risk management costs, the fluctuating Canadian dollar, higher operating costs and changes in future tax provisions due to the SIFT tax
and corporate tax rate reductions. The following table provides a summary of net income, cash flow and other key measures.

|($ millions, except per unit amounts) |  |   | 2009    |  |  |   | 2008    |  |   | 2007    | 
|------------------------------------- |  | - | ------- |  |  | - | ------- |  | - | ------- | 
|                                      |  |  
|Oil and gas sales(1)                  |  | $ | 1,232.8 |  |  | $ | 2,304.2 |  | $ | 1,517.1 | 
|Net income                            |  |   | 89.1    |  |  |   | 888.9   |  |   | 339.7   | 
|Per unit (Basic)(2)                   |  |   | 0.53    |  |  |   | 5.54    |  |   | 2.66    | 
|Per unit (Diluted)                    |  |   | 0.53    |  |  |   | 5.53    |  |   | 2.66    | 
|Cash flow from operating activities   |  |   | 775.8   |  |  |   | 1,262.8 |  |   | 868.5   | 
|Per unit (Basic)(2)                   |  |   | 4.58    |  |  |   | 7.86    |  |   | 6.80    | 
|Cash distributions to unitholders(3)  |  |   | 368.2   |  |  |   | 786.1   |  |   | 646.8   | 
|Per unit (Basic)(2)(3)                |  |   | 2.17    |  |  |   | 4.89    |  |   | 5.07    | 
|Payout ratio(4)                       |  |   | 47%     |  |  |   | 62%     |  |   | 74%     | 
|Adjusted payout ratio(4)              |  |   | 87%     |  |  |   | 109%    |  |   | 120%    | 
|Total assets                          |  | $ | 5,905.5 |  |  | $ | 6,230.1 |  | $ | 4,303.1 | 
|Long-term debt, net of cash(5)        |  | $ | 485.3   |  |  | $ | 657.4   |  | $ | 725.0   | 
|                                      |  |  

LIQUIDITY AND CAPITAL RESOURCES

Capital Markets and Enerplus' Credit Exposure

The capital markets have continued to improve since March 2009. On June 18, 2009 we successfully closed a private placement of senior unsecured
notes that raised gross proceeds of approximately $338.7 million. The proceeds were used to pay down bank indebtedness giving us additional financial flexibility. On September 9, 2009 we
closed an equity offering that raised gross proceeds of approximately $225 million. The majority of the proceeds were used to fund the cash portion of our Marcellus acquisition with the balance
used to reduce bank indebtedness.

With
the volatility in commodity prices we continue to place emphasis on evaluating credit capacity, understanding counterparty credit risk and overall liquidity concerns. We discuss these risks below
as they relate to our credit facility, oil and gas sales counterparties, financial derivative counterparties and joint venture partners.

Credit Facility

Our $1.4 billion bank credit facility is an unsecured, covenant-based, three-year term agreement maturing November 2010, through our
wholly-owned subsidiary EnerMark Inc., a copy of which was filed on March 18, 2008 as a "Material Document" on the Fund's SEDAR profile at www.sedar.com. Of the thirteen syndicate
members in this facility, seven are major Canadian banks which collectively represent approximately $985 million or 70% of the commitments under the $1.4 billion facility. We have the
ability to request an extension of the facility each year or repay the entire balance at the end of the term. Due to the high costs associated with extending the credit facility combined with recent
volatility in the credit markets we chose not to extend the term of our credit facility this year. Borrowing costs under the facility range between 55.0 and 110.0 basis points over bankers'
acceptance rates, with our current borrowing cost being 55.0 basis points over bankers' acceptance rates. Our borrowing costs are likely to increase upon renewal of our credit facility as
extension fees and pricing for drawn and undrawn balances have increased in the marketplace. We expect to renew our credit facility during the second quarter of 2010 prior to its expiry. At
December 31, 2009 the entire facility was undrawn and we were in compliance with all covenants under the facility.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY15

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Oil and Gas Sales Counterparties

Our oil and gas receivables are with customers in the petroleum and natural gas business and are subject to normal credit risks. Concentration of credit risk is
mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. A credit review process is in place to assess and monitor our counterparties' credit worthiness
on a regular basis. This process involves reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we
obtain financial assurances such as letters of credit, parental guarantees or third party insurance to mitigate our credit risk. This process is utilized for both our oil and gas sales counterparties
as well as our financial derivative counterparties.

Financial Derivative Counterparties

We are exposed to credit risk in the event of non-performance by our financial counterparties regarding our derivative contracts. We mitigate this
risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association ("ISDA")
agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other
under all outstanding transactions and settle with a single net amount in the case of a credit event. In the absence of an ISDA we rely on long form confirmations which provide us with similar credit
protection. At December 31, 2009 we had $22.3 million in mark-to-market assets offset by $92.2 million of mark-to-market
liabilities resulting in a net liability position of $69.9 million.

We
will continue to monitor developments in the financial markets that could impact the creditworthiness of our financial counterparties. To date we have not experienced any losses due to
non-performance by our derivative counterparties.

Joint Venture Partners

We attempt to mitigate the credit risk associated with our joint interest receivables by reviewing and actively following up on older accounts. In addition, we
are specifically monitoring our receivables against a watch list of publicly traded companies that have high debt-to-cash flow ratios or highly drawn bank facilities. We do not
anticipate any significant issues in the collection of our joint interest receivables at this time.

Distribution Policy

The amount of cash distributions paid to unitholders is proposed by management and approved by the Board of Directors. We continually assess distribution levels
with respect to anticipated cash flows, debt levels, capital spending plans and capital market conditions. The level of cash withheld varies and is dependent upon numerous factors, the most
significant of which are the prevailing commodity price environment, our current levels of production, debt obligations, funding requirements for our development capital program and our access to
equity markets.

We
have maintained our monthly distribution rate of $0.18 per unit distribution since February 2009 and have been able to manage our distribution levels and capital spending in order to
minimize increases in our debt levels and preserve our balance sheet strength.

Sustainability of our Distributions and Asset Base

As an oil and gas producer we have a declining asset base and therefore rely on ongoing development activities and acquisitions to replace production and add
additional reserves. Our future crude oil and natural gas production is highly dependent on our success in exploiting our asset base and acquiring or developing additional reserves. To the extent we
are unsuccessful in these activities, our cash distributions could be reduced.

Development
activities and acquisitions may be funded internally by withholding a portion of cash flow or through external sources of capital such as debt or the issuance of equity. To the extent that
we withhold cash flow to finance these activities, the amount of cash distributions to our unitholders may be reduced. Should external sources of capital become limited or unavailable, our ability to
make the necessary development expenditures and acquisitions to maintain or expand our asset base may be impaired and ultimately reduce the amount of cash distributions.

Our
2010 development capital spending is expected to be $425 million (net of DRC credits) which represents a 42% increase from 2009 spending of $299.1 million. We expect to exit
2010 with production of approximately 88,000 BOE/day.

16      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Should
we choose to issue equity in conjunction with an acquisition we do not anticipate any constraints for our growth strategy stemming from the Canadian Government's "normal growth" guidelines for
SIFT's as we currently have approximately $9 billion of safe harbour growth capacity.

Cash Flow from Operating Activities, Cash Distributions and Payout Ratio

Cash flow from operating activities and cash distributions are reported on the Consolidated Statements of Cash Flows. During 2009 cash distributions of
$368.2 million were funded entirely through cash flow of $775.8 million.

Our
payout ratio, which is calculated as cash distributions divided by cash flow, was 47% for 2009 compared to 62% in 2008. Our adjusted payout ratio, which is calculated as the sum of cash
distributions plus development capital and office expenditures divided by cash flow, was 87% for 2009 compared to 109% in 2008. The decrease in our payout ratio and adjusted payout ratio is due to the
reduction in our monthly cash distributions and capital spending along with changes in our working capital balances that impact cash flow. See "Non-GAAP Measures" above.

For
the year ended December 31, 2009 our cash distributions exceeded our net income by $279.1 million whereas in 2008 our net income exceeded our cash distributions by
$102.8 million. Non-cash items such as changes in the fair value of our derivative instruments and future income taxes cause net income to fluctuate between periods but do not
reduce or increase our cash flow. Future income taxes can fluctuate from period to period as a result of changes in tax rates as well as changes in interest, royalties and dividends from our operating
subsidiaries paid to the Fund. In addition, we believe that other non-cash charges such as DDA&A are not a good
proxy for the cost of maintaining our productive capacity as they are based on the historical cost of our PP&E and not the fair market value of replacing those assets within the context of the current
environment.

It
is not practical to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities in the oil and gas sector due to the nature of reserve reporting,
natural reservoir declines and the risks involved with capital investment. As a result, we do not distinguish maintenance capital separately from development capital spending. The level of investment
in a given period may not be sufficient to replace productive capacity given the natural declines associated with oil and natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.

The
following table compares cash distributions to cash flow and net income.

|($ millions, except per unit amounts)                    |  |   | 2009   |   |  |  |   | 2008    |  |   | 2007   |   | 
|-------------------------------------------------------- |  | - | ------ | - |  |  | - | ------- |  | - | ------ | - | 
|                                                         |  |  
|Cash flow from operating activities                      |  | $ | 775.8  |   |  |  | $ | 1,262.8 |  | $ | 868.5  |   | 
|Cash distributions                                       |  |   | 368.2  |   |  |  |   | 786.1   |  |   | 646.8  |   | 
|                                                         |  |  
|Excess of cash flow over cash distributions              |  | $ | 407.6  |   |  |  | $ | 476.7   |  | $ | 221.7  |   | 
|Net income                                               |  | $ | 89.1   |   |  |  | $ | 888.9   |  | $ | 339.7  |   | 
|(Shortfall)/excess of net income over cash distributions |  | $ | (279.1 | ) |  |  | $ | 102.8   |  | $ | (307.1 | ) | 
|Cash distributions per weighted average trust unit       |  | $ | 2.17   |   |  |  | $ | 4.89    |  | $ | 5.07   |   | 
|Payout ratio(1)                                          |  |   | 47%    |   |  |  |   | 62%     |  |   | 74%    |   | 
|Adjusted payout ratio(1)                                 |  |   | 87%    |   |  |  |   | 109%    |  |   | 120%   |   | 
|                                                         |  |  

Debt

In the second quarter of 2009 we closed a private offering of senior unsecured notes that raised gross proceeds of approximately $338.7 million. The
proceeds from the offering repaid a portion of our outstanding bank debt, which increased the available credit under our bank facility. See Note 6 for a detailed list of our notes along with
the terms and rates.

Total
debt at December 31, 2009 was $558.9 million comprised solely of senior unsecured notes including the current portion of $36.6 million and the long-term portion
of $522.3 million. This represents a decrease of $105.4 million from $664.3 million at December 31, 2008. Our credit facility was undrawn at December 31, 2009
compared to a drawn balance of $380.9 million at December 31, 2008. This decrease in our bank indebtedness is primarily due to the proceeds from our June 2009 offering of senior
unsecured notes and a portion of the proceeds from our September 2009 equity offering being applied against bank indebtedness. As well, we supported our distributions and capital expenditures
with our cash flows during the year in order to preserve our balance sheet strength.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY17

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We expect that our debt levels may increase marginally through 2010 based on our current development plans, distribution levels and forward commodity prices and disregarding potential acquisitions or
divestments. Given our focus on early stage resource plays such as the Marcellus, Deep Basin, and Bakken, we will consider investment and distribution levels that modestly exceed cash flow provided we
retain balance sheet strength and achieve compelling economics on our development capital program.

Our
working capital at December 31, 2009, excluding cash, current deferred financial assets and credits, future income taxes and current portion of long-term debt, increased by
$4.9 million compared to December 31, 2008. This change was due to decreased accounts payable that resulted from lower capital spending activity along with decreased distributions
payable as a result of the reduction in our monthly distributions partially offset by decreased accounts receivable.

We
have preserved a conservative balance sheet as demonstrated below which will support our growth plans:

|Financial Leverage and Coverage                      |  | Year ended
Dec. 31, 2009 |  |  | Year ended
Dec. 31, 2008 | 
|---------------------------------------------------- |  | ------------------------ |  |  | ------------------------ | 
|                                                     |  |                         
|Long-term debt to cash flow (12 month trailing)(1)   |  | 0.6 x                    |  |  | 0.5 x                    | 
|Cash flow to interest expense (12 month trailing)(2) |  | 25.4 x                   |  |  | 29.6 x                   | 
|Long-term debt to long-term debt plus equity(1)      |  | 10%                      |  |  | 13%                      | 
|                                                     |  |                         

Payments with respect to the bank facilities, senior unsecured notes and other third party debt have priority over claims of and future distributions to the
unitholders. Unitholders have no direct liability should cash flow be insufficient to repay this indebtedness. The agreements governing these bank facilities and senior unsecured notes stipulate that
if we default or fail to comply with certain covenants, the ability of the Fund's operating subsidiaries to make payments to the Fund and consequently the Fund's ability to make distributions to the
unitholders may be restricted. At December 31, 2009, we were in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing
cash flow.

We
expect to have adequate liquidity under our bank credit facility and from cash flow to fund planned development capital spending and working capital requirements for 2010.

Principal
payments on our senior unsecured notes are required starting in 2010 and are more fully discussed below under "Commitments" and Notes 6 and 12.

COMMITMENTS

We have contracted to transport 132 MMcf/day of natural gas on the TransCanada system in Alberta, 46 MMcf/day on TransGas in Saskatchewan,
32 MMcf/day in B.C.via Spectra, as well as 9 MMcf/day on the Alliance pipeline to the U.S. midwest. We have contracted gas gathering capacity of 4,500 MMbtu/day effective
March 1, 2010 and increasing to 6,000 MMbtu/day on May 1, 2010 for our Marcellus production.

Our
gas supply dedicated to aggregator sales contracts will be approximately 7% of gross gas production or 22 MMcf/day. 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.

In
addition, we also have a contract to transport a minimum of 1,698 bbls/day of crude oil from field locations to suitable marketing sales points within western Canada during the first quarter
of 2010. This delivery commitment expires March 31, 2010.

Our
U.S. and Canadian office leases expire in 2011 and 2014 respectively. Annual costs of these lease commitments include rent and operating fees. Our commitments, contingencies and guarantees are
more fully described in Note 12.

18      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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As
at December 31, 2009 we have the following minimum annual commitments including long-term debt:

|                              |  |   |             |  |  | Minimum Annual Commitment Each Year |       |  | Total Committed |      
|----------------------------- |  | - | ----------- |  |  | ----------------------------------- | ----- |  | --------------- | -----
|($ millions)                  |  |   | Total       |  |  |                                     | 2010  |  |                 | 2011 
|                              |  |  
|Bank credit facility          |  | $ |            |  |  | $                                   |      |  | $               |     
|Senior unsecured notes        |  |   | 640.6(1)(2) |  |  |                                     | 53.6  |  |                 | 64.6 
|Pipeline commitments          |  |   | 61.8        |  |  |                                     | 19.0  |  |                 | 13.9 
|Processing commitments        |  |   | 9.7         |  |  |                                     | 5.3   |  |                 | 1.4  
|Marcellus carry commitment(4) |  |   | 248.3       |  |  |                                     | 64.0  |  |                 | 120.3
|Office lease                  |  |   | 60.6        |  |  |                                     | 11.4  |  |                 | 12.5 
|                              |  |  
|Total commitments(3)          |  | $ | 1,021.0     |  |  | $                                   | 153.3 |  | $               | 212.7
|                              |  |  

ACCUMULATED DEFICIT

We have historically paid cash distributions in excess of accumulated earnings as cash distributions are based on the actual cash flow generated in the period,
whereas accumulated earnings are based on net income which includes non-cash items such as DDA&A charges, derivative instrument mark-to-market gains and losses,
unit based compensation charges and future income tax provisions.

TRUST UNIT INFORMATION

On September 9, 2009, in conjunction with the Marcellus property acquisition, we completed an equity offering of 10,406,000 trust units at a price
of $21.65 per unit for gross proceeds of approximately $225.3 million ($213.5 million net of issuance costs).

We
had 177,061,000 trust units outstanding at December 31, 2009 compared to 165,590,000 trust units outstanding at December 31, 2008. At December 31, 2009 this
includes 6,382,000 exchangeable limited partnership units which are convertible at the option of the holder into 0.425 of an Enerplus trust unit (2,712,000 trust units). During 2009, a
total of 856,000 partnership units were converted into 364,000 trust units.

During
2009, 1,065,000 trust units (2008  1,881,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan
("DRIP") and the trust unit rights incentive plan, net of redemptions. This resulted in $24.2 million (2008  $70.5 million) of additional equity to
the Fund. For further details see Note 9.

The
weighted average basic number of trust units outstanding during 2009 was 169,280,000 compared to 160,589,000 trust units during 2008. At February 16, 2010 we had
177,132,521 trust units outstanding including the equivalent limited partnership units.

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 Unitholders

We qualify as a mutual fund trust under the Income Tax Act (Canada) and accordingly, trust units of Enerplus are qualified investments for RRSPs, RRIFs,
RESPs, DPSPs and TFSAs. Each year we have historically transferred all of our taxable income to our unitholders by way of distributions.

In
computing income, unitholders are required to include the taxable portion of distributions received 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.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY19

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We
paid $2.16 per trust unit in cash distributions to unitholders on record during 2009. For Canadian tax purposes, approximately 2% of these distributions, or $0.04 per trust unit was a tax deferred
return of capital, approximately 98% or $2.12 per trust unit was taxable to unitholders as other income.

For
2010, we estimate that 95% of cash distributions will be taxable and 5% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are
dependent upon, among other things, production, commodity prices and cash flow experienced throughout the year.

U.S. Unitholders

U.S. unitholders who received cash distributions are subject to at least a 15% Canadian withholding tax. The withholding tax is applied to both the
taxable portion of the distribution as computed under Canadian tax law and the non-taxable portion of the distribution. U.S. taxpayers may be eligible for a foreign tax credit with
respect to Canadian withholding taxes paid.

For
U.S. taxpayers the taxable portion of cash distributions are considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers this should be a "Qualified Dividend"
eligible for the reduced tax rate. The 15% preferred rate of tax on "Qualified Dividends" is currently scheduled to expire at the end of 2010. We are unable to determine whether or to what extent the
preferred rate of tax on "Qualified Dividends" may be extended.

We
paid US$1.95 per trust unit to U.S. residents during the 2009 calendar year of which approximately 14% or US$0.27 per trust unit was a tax deferred return of capital and approximately 86% or
US$1.68 per unit was a qualified dividend.

For
2010, we estimate that 90% of cash distributions will be taxable to most U.S. investors and 10% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual
distributions which are dependent upon production, commodity prices and cash flow experienced throughout the year.

QUARTERLY FINANCIAL INFORMATION

Crude oil and natural gas sales increased to mid-2008 due to increased commodity prices and increased production from the Focus acquisition. Oil and
natural gas sales decreased in the latter part of 2008 with the sharp decline in commodity prices and were flat during 2009 as rising crude oil prices have largely been offset by declining natural gas
prices. Our reduced production levels in 2009 have also put downward pressure on oil and gas sales.

Net
income has been affected by fluctuating commodity prices and risk management costs and the fluctuating Canadian dollar.

|                                               |  |   | Oil and   |     |   | Net          |   | Net Income/(Loss) Per Trust Unit
|---------------------------------------------- |  | - | --------- | --- | - | ------------ | - | --------------------------------
|(CDN$ millions, except per trust unit amounts) |  |   | Gas Sales | (1) |   | Income/(Loss | ) |                                 
|                                              
|2009                                           |  |   |           |     |   |              |   |                                 
|Fourth Quarter                                 |  | $ | 333.3     |     | $ | 2.7          |   | $                               
|Third Quarter                                  |  |   | 292.1     |     |   | 38.2         |   |                                 
|Second Quarter                                 |  |   | 306.2     |     |   | (3.6         | ) |                                 
|First Quarter                                  |  |   | 301.2     |     |   | 51.8         |   |                                 
|                                               |  |   |           |     |   |              |   |                                 
|Total                                          |  | $ | 1,232.8   |     | $ | 89.1         |   | $                               
|                                              
|2008                                           |  |   |           |     |   |              |   |                                 
|Fourth Quarter                                 |  | $ | 418.3     |     | $ | 189.5        |   | $                               
|Third Quarter                                  |  |   | 647.8     |     |   | 465.8        |   |                                 
|Second Quarter                                 |  |   | 734.4     |     |   | 112.2        |   |                                 
|First Quarter                                  |  |   | 503.7     |     |   | 121.4        |   |                                 
|                                               |  |   |           |     |   |              |   |                                 
|Total                                          |  | $ | 2,304.2   |     | $ | 888.9        |   | $                               
|                                              

20      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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SUMMARY FOURTH QUARTER INFORMATION

In comparing the fourth quarter of 2009 with the same period in 2008:

The
following tables provide an analysis of key financial and operating results for the three months ended December 31, 2009 and 2008.

|(CDN$ millions, except per unit amounts)                                       |  |   | Three Months Ended
December 31, 2009 |   |  |  |   | Three Months Ended
December 31, 2008 |   | 
|------------------------------------------------------------------------------ |  | - | ------------------------------------ | - |  |  | - | ------------------------------------ | - | 
|                                                                               |  |  
|Financial (000's)                                                              |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income                                                                     |  | $ | 2.7                                  |   |  |  | $ | 189.5                                |   | 
|Cash Flow from Operating Activities                                            |  | $ | 188.6                                |   |  |  | $ | 258.5                                |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 95.5                                 |   |  |  | $ | 167.0                                |   | 
|Financial per Unit(2)                                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income                                                                     |  | $ | 0.02                                 |   |  |  | $ | 1.15                                 |   | 
|Cash Flow from Operating Activities                                            |  | $ | 1.07                                 |   |  |  | $ | 1.56                                 |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 0.54                                 |   |  |  | $ | 1.01                                 |   | 
|Payout Ratio(3)                                                                |  |   | 51%                                  |   |  |  |   | 65%                                  |   | 
|Adjusted Payout Ratio(3)                                                       |  |   | 114%                                 |   |  |  |   | 144%                                 |   | 
|Average Daily Production                                                       |  |   | 86,777                               |   |  |  |   | 97,702                               |   | 
|Selected Financial Results per BOE(4)                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Oil and Gas Sales(5)                                                           |  | $ | 41.75                                |   |  |  | $ | 46.54                                |   | 
|Royalties                                                                      |  |   | (6.56                                | ) |  |  |   | (8.61                                | ) | 
|Commodity Derivative Instruments                                               |  |   | 3.34                                 |   |  |  |   | 3.54                                 |   | 
|Operating Costs                                                                |  |   | (9.27                                | ) |  |  |   | (9.46                                | ) | 
|General and Administrative                                                     |  |   | (3.30                                | ) |  |  |   | (1.71                                | ) | 
|Interest and Foreign Exchange                                                  |  |   | (0.72                                | ) |  |  |   | (2.73                                | ) | 
|Taxes                                                                          |  |   | 0.66                                 |   |  |  |   | 0.92                                 |   | 
|Restoration and Abandonment                                                    |  |   | (0.64                                | ) |  |  |   | (0.53                                | ) | 
|                                                                               |  |  
|Cash Flow from Operating Activities before changes in non-cash working capital |  | $ | 25.26                                |   |  |  | $ | 27.96                                |   | 
|                                                                               |  |  
|Weighted Average Number of Units Outstanding (thousands)                       |  |   | 176,872                              |   |  |  |   | 165,373                              |   | 
|Development Capital                                                            |  |   | 118.9                                |   |  |  |   | 200.3                                |   | 
|Net Wells Drilled                                                              |  |   | 156                                  |   |  |  |   | 174                                  |   | 
|Success Rate                                                                   |  |   | 99%                                  |   |  |  |   | 99%                                  |   | 
|Average Benchmark Pricing                                                      |  |   |                                      |   |  |  |   |                                      |   | 
|AECO natural gas  monthly index (CDN$/Mcf)                                    |  | $ | 4.24                                 |   |  |  | $ | 6.79                                 |   | 
|AECO natural gas  daily index (CDN$/Mcf)                                      |  | $ | 4.50                                 |   |  |  | $ | 6.68                                 |   | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                                |  | $ | 4.27                                 |   |  |  | $ | 6.77                                 |   | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf)              |  | $ | 4.49                                 |   |  |  | $ | 8.26                                 |   | 
|WTI crude oil (US$/bbl)                                                        |  | $ | 76.19                                |   |  |  | $ | 58.73                                |   | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                                      |  | $ | 80.20                                |   |  |  | $ | 71.62                                |   | 
|CDN$/US$ exchange rate                                                         |  |   | 0.95                                 |   |  |  |   | 0.82                                 |   | 
|                                                                               |  |  

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY21

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SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS

|                                         |                                                     | Three months ended December 31, 2009 |        | Three months ended December 31, 2008
|---------------------------------------- | --------------------------------------------------- | ------------------------------------ | ------ | ------------------------------------
|(CDN$ millions, except per unit amounts) |                                                     |                                      | Canada |                                     
|                                         |                                                     |                                     
|Average Daily Production Volumes         |                                                     |                                      |        |                                     
|                                         | Natural gas (Mcf/day)                               |                                      |        | 291,833                             
|                                         | Crude oil (bbls/day)                                |                                      |        | 24,271                              
|                                         | Natural gas liquids (bbls/day)                      |                                      |        | 4,238                               
|                                         | Total daily sales (BOE/day)                         |                                      |        | 77,148                              
|Pricing(1)                               |                                                     |                                      |        |                                     
|                                         | Natural gas (per Mcf)                               |                                      | $      | 3.95                                
|                                         | Crude oil (per bbl)                                 |                                      | $      | 67.07                               
|                                         | Natural gas liquids (per bbl)                       |                                      | $      | 56.96                               
|Capital Expenditures                     |                                                     |                                      |        |                                     
|                                         | Development capital and office                      |                                      | $      | 99.2                                
|                                         | Acquisitions of oil and gas properties              |                                      | $      | 2.3                                 
|                                         | Dispositions of oil and gas properties              |                                      | $      | (102.1                              
|Revenues                                 |                                                     |                                      |        |                                     
|                                         | Oil and gas sales(1)                                |                                      | $      | 277.7                               
|                                         | Royalties                                           |                                      | $      | (39.4                               
|                                         | Commodity derivative instruments gain/(loss)        |                                      | $      | 14.5                                
|Expenses                                 |                                                     |                                      |        |                                     
|                                         | Operating                                           |                                      | $      | 70.5                                
|                                         | General and administrative                          |                                      | $      | 25.5                                
|                                         | Depletion, depreciation, amortization and accretion |                                      | $      | 148.8                               
|                                         | Current income taxes                                |                                      | $      |                                    
|                                         |                                                     |                                     

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 the full cost and the successful efforts methods of accounting.

We
apply the full cost method of accounting for oil and natural gas activities. Under 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 not exploratory in nature.

Under
the full cost method of accounting, an impairment test is applied to the overall carrying value of property, plant and equipment, on a country by country cost centre basis 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 method of accounting may generate a different carrying value of property, plant and equipment and a different net income
depending on the circumstances at period end. Net costs related to operating and administrative activities during the development of large capital projects are capitalized until commercial production
has commenced and are tested for impairment separately under full cost accounting.

22      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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CRITICAL ACCOUNTING ESTIMATES

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

Reserves

The process of estimating reserves is critical to several accounting estimates. It requires significant judgments 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 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.

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon and reclaim its 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 PP&E as part of the cost of the related asset and amortized over its useful life.

Business Combinations

Management makes various assumptions in determining the fair values of any acquired company's assets and liabilities in a business combination. The most
significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we estimate (a) oil and gas
reserves in accordance with National Instrument 51-101  Standards of Disclosure for Oil and Gas Activities ("NI 51-101")
adopted by the Canadian Securities regulatory authorities reserve standards, and (b) future prices of oil and gas.

Commodity Prices

Management's estimates of future crude oil and natural gas prices are critical as these prices are used to determine the carrying amount of PP&E, assess
impairment in our cost centers, and determine the change in fair value of financial contracts. Management's estimates of prices are based on the price forecast from our reserve engineers and the
current forward market.

Trust Unit Rights

Management calculates the fair value of rights granted under our trust unit rights incentive plan using a binomial lattice option-pricing model. This process
involves the use of significant estimates and assumptions which may change over time. The values calculated under the option-pricing model may not reflect the actual value realized by trust unit
rights holders.

Derivative Financial Instruments

We utilize derivative financial instruments to manage our exposure to market risks relating to commodity prices, foreign currency exchange rates and interest
rates. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates and counterparty
credit risk.

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Current Year Accounting Changes

During 2009, the Fund adopted the following new accounting standards or amendments that were issued by the Canadian Institute of Chartered Accountants ("CICA"):
Handbook Section 3064, Goodwill and Intangible Assets, Section 3862, Financial Instruments  Disclosures and Emerging Issues Committee
("EIC") 173  Credit Risk and the Fair Value of Financial Assets and Financial Liabilities.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY23

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Goodwill and Intangible Assets

Section 3064 replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The
new Section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill
are unchanged from the standards included in the previous Section 3062. The adoption of this new standard did not have a material impact on the Fund's Consolidated Financial Statements.

Financial Instruments  Disclosures

Section 3862 was amended to include additional disclosure requirements about fair value measurement for financial instruments and liquidity risk
disclosures. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities included in
Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than
quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair
value measurement. The adoption of this new standard did not have a material impact on the Fund's Consolidated Financial Statements.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

EIC-173 provides guidance on how to take into account the credit risk of an entity and counterparty when determining the fair value of
financial assets and financial liabilities, including derivative instruments. The adoption of EIC-173 did not have a material impact on the Fund's Consolidated Financial Statements.

These
standards were adopted prospectively.

Future Accounting Changes

Business Combinations

In January 2009, the CICA issued Handbook Section 1582, Business Combinations that replaces the previous business combinations standard. Under the
new standard, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price
used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the new standard generally requires all
acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new standard also addresses contingent liabilities, which will be
required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Current standards require only contingent liabilities that are due to be
recognized. The new standard requires any negative goodwill to be recognized as a charge to earnings rather than the current standard of which reduces the fair value of non-current assets
in the purchase price allocation. The new standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. We do not intend to early adopt
the new standard.

Convergence of Canadian GAAP with International Financial Reporting Standards ("IFRS")

In October 2009 the Accounting Standards Board ("AcSB") issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable
enterprises will be required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011. The adoption date of January 1, 2011 will require the
restatement, for comparative purposes, of amounts reported by Enerplus for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

In
order to meet our reporting requirements and transition to IFRS we have established a project team comprised of individuals from Finance, Information Systems, Business Solutions, Operations, Tax,
Investor Relations and Management. Our transition plan consists of four main phases:

24      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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To
date we have completed our IFRS diagnostic. As we have not yet finalized our accounting policies, we are unable to quantify the impact of adopting IFRS on our financial statements. In addition, due
to anticipated changes to IFRS and International Accounting Standards ("IAS") prior to our adoption of IFRS, our policy choices are subject to change based on new facts and circumstances that arise
after the date of this MD&A.

As
a result of our information system evaluation and assessments in 2009, we have implemented certain system changes in late 2009 to facilitate the classification of our PP&E in accordance with IFRS
requirements in 2010. Therefore, we will be able to capture the 2010 comparative information required for our 2011 reporting under IFRS.

Internal Control Over Financial Reporting ("ICFR") and Disclosure Controls and Procedures ("DC&P")

In implementing the changes required for the transition to IFRS we have considered the integrity of our ICFR and DC&P. We do not expect significant changes to
our ICFR and DC&P, however we will continue to assess the impact to ICFR and DC&P during 2010 should additional changes be made to information systems, business processes, or our accounting policies.

During
2009 we provided regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS transition. In addition, we provided targeted training on capital asset
changes to our operations groups and business analysis teams. More comprehensive training was provided to members of our Executive, Board of Directors and Corporate Finance group with a focus on the
most significant IFRS accounting policy changes that may impact our 2011 financial statements.

IFRS 1 Voluntary Exemptions Applied

First-Time Adoption of International Financial Reporting Standard("IFRS 1") allows first time
adopters certain exemptions from the general requirement to apply IFRS retrospectively. In July 2009, International Accounting Standards Board ("IASB") finalized an amendment to IFRS 1
that allows a first-time adopter using full cost accounting to elect to measure its oil and gas assets at the date of transition to IFRS based on the entity's previous GAAP carrying value.
This standard is effective for years beginning on or after January 1, 2010 with early adoption permitted.

As
of the date of this MD&A, we expect to apply the following voluntary IFRS 1 exemptions at the date of transition:

Key Accounting Policy Differences

The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of
operations. First time adoption impacts of IFRS are reflected through opening balance sheet transitional entries, the majority of which are expected to be offset to retained earnings. The key
differences between existing Canadian GAAP and IFRS that impact us are presented below.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY25

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Property, Plant and Equipment

Under IFRS capital costs will be recorded using one of the following three categories:

a. Pre-Exploration Costs

Under Canadian GAAP costs incurred prior to having obtained the legal right to explore are capitalized using the full cost method of accounting. Under IFRS such
expenditures are expensed as incurred.

b. Exploration and Evaluation ("E&E") Assets

E&E assets are assets that are not considered by management to be commercially viable or technically feasible. These would include our oil sands assets and
undeveloped land. Under Canadian GAAP E&E assets are not separately identified whereas IFRS requires E&E assets to be separately identified on the face of the balance sheet as tangible or intangible
assets.

c. Developed and Producing ("D&P") Assets

Under Canadian GAAP D&P assets are capitalized using the full cost method of accounting. Under IFRS D&P assets are accounted for in smaller cost centers, or
CGUs, and recognized on the balance sheet separately from E&E assets.

As
a result of the changes in accounting for PP&E under IFRS we expect a moderate decrease in the overall capitalization of our development capital and acquisition expenditures.

Depletion Policy

Under Canadian GAAP depletion is based on a unit of production basis using proved reserves. Under IFRS we have a choice to deplete our D&P assets on a unit of
production basis using either proved or proved plus probable reserves for each CGU. We expect to adopt a policy of depleting using proved plus probable reserves for each CGU, which would reduce the
amount of depletion recorded.

Impairment of Assets

Canadian GAAP generally uses a two-step approach to impairment testing. The first compares the asset carrying value with undiscounted future cash
flows to determine whether an impairment exists. If an impairment exists the amount of the impairment is determined by comparing the asset carrying value with the discounted future cash flows.
IAS 36, "Impairment of Assets", uses a one-step approach for both testing and measurement of impairment whereby the asset carrying value is compared directly with the discounted
future cash flows of the asset.

At
each reporting date all E&E assets and D&P assets are assessed for indicators of impairment. When indicators of a possible impairment exist, an impairment test is performed. Impairment tests are
carried out at the CGU level, or based on a group of CGUs. In addition to performing an impairment test when indicators are present, impairment tests occur prior to the transfer of E&E assets into the
D&P asset class. Intangible assets, like goodwill, are tested for impairment annually. Any write-downs required will first reduce goodwill to zero before impacting the value of the E&E or D&P asset.
This may result in more write-downs under IFRS compared to Canadian GAAP.

As
a result of selecting the IFRS 1 exemption noted above, we are required to perform impairment tests on our assets at the date of transition, January 1, 2010. We have not assessed the
impact at this time.

Canadian
GAAP prohibits reversal of impairment losses. Under IFRS if the conditions giving rise to impairment have reversed, impairment losses previously recorded would be partially or fully reversed
to eliminate write-downs recorded.

26      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Decommissioning Liabilities (or Asset Retirement Obligations under Canadian GAAP)

Under Canadian GAAP we recognize a liability for the estimated fair value of the future retirement obligations associated with PP&E. The fair value is
capitalized and amortized over the same period as the underlying asset. We estimate the liability based on the estimated costs to abandon and reclaim our net ownership interest in wells and
facilities, including an estimate for the timing of the costs to be incurred in future periods. These cash outflows are discounted using a credit-adjusted risk free rate. Changes in the net present
value of the future retirement obligation are expensed through accretion as part of DDA&A.

Under
IFRS decommissioning liabilities are included as part of IAS 37, "Provisions, Contingent Liabilities and Contingent Assets". The liability is calculated at each reporting period using
estimates of risk-adjusted future cash outflows discounted using the risk free rate. Changes in the net present value of the future retirement obligation are expensed through accretion as
a part of DDA&A.

As
a result of the change in the discount rate from a credit-adjusted rate to a risk free rate, we expect there may be an increase in the value of the decommissioning liability under IFRS compared to
Canadian GAAP, however the difference, if any, is not known at this time.

Marketable Securities

Under Canadian GAAP investments for non-public companies are carried at cost. Under IFRS all investments, public or private, must be carried at fair
value and revalued at each reporting date. Enerplus expects this may have an impact on the carrying value of our marketable securities under IFRS as these values fluctuate over time.

Other Considerations

As a result of the combined IFRS changes noted in the preceding paragraphs, Management has been actively working with counterparties to ensure agreements entered
into that make reference to Canadian GAAP statements are modified to allow for IFRS financial statements. This communication was in place during 2009 and such provisions were included in the
agreements related to the issuance of our senior unsecured notes on June 18, 2009. As such, we do not anticipate issues with our existing debt covenants and related agreements at this time;
however we will continue to monitor this during 2010.

RISK FACTORS AND RISK MANAGEMENT

Commodity Price Risk

Our operating results and financial condition are dependent on the prices we receive for our crude oil and natural gas production. These prices have fluctuated
widely in response to a variety of factors including global and domestic demand, 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 may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of natural gas and crude 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 may use financial derivative instruments 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. Refer to the "Price Risk Management" section for
further details on our price risk management program.

Availability of Credit and Renewal Risk

As a result of the global credit crisis during 2009 the fees and borrowing costs associated with renewing our bank credit facility were extremely high. Therefore
we decided to delay the renewal of our $1.4 billion facility which expires on November 18, 2010. Although we expect to renew the facility during the second quarter of 2010, we have no
assurance that the credit markets will be favorable at that time or that all our banks will renew at their current commitment levels.

At December 31, 2009, our entire $1.4 billion bank credit facility was undrawn. Approximately 70% of the commitments under this facility are with major Canadian
banks who have indicated they would be supportive of our renewal in 2010 and are considered to be among the most sound credit providers. Our borrowing costs are likely to increase upon renewal of our
credit facility as extension fees and pricing for drawn and undrawn balances have generally increased in the marketplace.

See the "Liquidity and Capital Resources" section for further information related to our credit facility.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY27

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Counterparty and Joint Venture Credit Exposure

Early in 2009 economic conditions negatively affected the availability of credit and increased the risk that certain counterparties for our oil and gas sales,
financial derivatives and operations may fail to pay. Generally credit markets have improved however there remains a risk that our counterparties may experience financial problems. Furthermore, if oil
and natural gas prices remain low there is a risk of increased bad debts related to our joint venture industry partners.

A credit review process is in place to assess and monitor our counterparties' credit worthiness on a regular basis. This includes reviewing and ratifying our corporate credit
guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we obtain financial assurances such as letters of credit, parental guarantees, or third party
insurance to mitigate our counterparty risk. In addition, we monitor our receivables against a watch list of publicly traded companies that have high debt-to-cash flow ratios
or fully drawn bank facilities. In certain instances we may be able to aggregate all amounts owing to each other and settle with a single net amount.

See the "Liquidity and Capital Resources" section for further information related to our counterparties and joint venture partners.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through equity and debt and as a result, distribute a
significant portion of our cash flow to our unitholders. Although we are somewhat dependent on continued access to the capital market to fund our acquisition activity, we have chosen to reduce our
reliance on the market by balancing the level of capital spending and distributions more closely to our cash flow. Continued access to capital is dependent 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.

We are listed on the Toronto and New York stock exchanges and maintain an active investor relations program. We provide continuous disclosure and maintain complete public
filings to ensure our eligibility to file a short form prospectus under applicable Canadian securities law.

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

Oil and Gas Reserves and Resources Risk

The value of our trust units are based on, among other things, the underlying value of the oil and gas reserves and resources. Geological and operational risks
along with product price forecasts can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower crude oil and natural gas
prices along with lower development capital spending associated with certain projects may increase the risk of write-downs for our oil and gas property investments. Changes in reporting methodology as
well as regulatory reporting practices can result in reserve or resource write-downs.

We strive to acquire assets with positive operating metrics, long reserve lives and significant growth or cash flow potential. Where we do engage in higher risk activities we
target areas where there is potential for larger scale repeatable resource development if successful.

Each year, independent engineers evaluate a significant portion of our proved and probable reserves as well as the resources attributable to our oil sands properties and
Marcellus shale gas properties.

McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated 90% of the total proved plus probable value (discounted at 10%) of our Canadian conventional
year-end reserves and have reviewed the remainder of the reserves which we have evaluated internally. Netherland, Sewell & Associates Inc. ("NSAI") of Dallas, Texas,
evaluated 100% of the reserves attributed to our western US assets including the Sleeping Giant field and Haas Petroleum Engineering Services, Inc. ("Haas") evaluated 100% of the reserves and
contingent resources associated with our Marcellus shale gas property in the eastern United States. GLJ Petroleum Consultants Ltd. ("GLJ") evaluated the contingent resources attributable
to our Kirby oil sands leases.

To ensure comparability all of the independent reserve engineering firms utilized McDaniel's forecast prices, constant prices and cost assumptions as of December 31, 2009
and evaluated our reserves in accordance with NI 51-101.

The Reserves Committee of the Board of Directors has reviewed and approved the reserve and resource reports of the independent evaluators.

28      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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Marcellus Shale Gas

The Marcellus properties represent a new focus on shale gas outside of our traditional geographic areas. We have very limited experience in the drilling and
development of shale gas properties including the Marcellus shale gas region. The expansion of our activities into this new resource play and location may present challenges and risks that we have not
faced in the past. Failure to manage these challenges and risks successfully may adversely affect the results of our operations and financial condition.

We purchased a non-operated position and intend to initially rely upon our partner's expertise, Chief Oil & Gas LLC ("Chief"), with respect to ongoing
development, operations and certain future expansions in the Marcellus shale gas region. Furthermore, we expect to utilize Chief's knowledge to enhance our in-house technical expertise
through a close working relationship.

Minimum Royalty Litigation May Invalidate Marcellus Leases

A significant amount of the lands that we acquired in the Marcellus shale gas region are located in the state of Pennsylvania, which has legislation requiring
the lessee of a freehold oil and gas lease to provide the lessor with a minimum royalty equal to 1/8th of the hydrocarbons produced from the leased lands. Currently there are several legal
actions proceeding in the state including various third parties that claim any reduction in the royalty related to post-production costs such as gathering, processing and marketing of the
production results in the lessor receiving less than the minimum royalty and therefore invalidates the lease.

The majority of the leases we acquired pursuant to our Marcellus acquisition provide for the deduction of post-production costs from the lessor's royalty share of
production. Chief has advised us that they have taken certain steps to mitigate this risk, and in particular to enter into lease amendments with respect to developed properties. There is no assurance
that the courts hearing these matters will rule in favour of validating these leases and it is possible that an adverse ruling could result in the loss of some or all of the economic benefit of the
leases we acquired.

Access to Transportation Capacity

Market access for crude oil and natural gas production in Canada and the United States is dependent on our ability to access sufficient transportation
capacity on third party pipelines to transport all production volumes. New resource plays, such as the U.S. Marcellus shale gas, generally experience a sharp increase in the amount of
production being produced in the area which could exceed the existing capacity of the various gathering and pipeline infrastructure. While the third party pipelines generally expand capacity to meet
market needs, there can be differences in timing between the growth of production and the growth of pipeline capacity. There are also occasionally operational reasons for curtailing transportation
capacity. Accordingly, there can be periods where transportation capacity is insufficient to accommodate all of the production from a given region, causing added expense and/or volume curtailments for
all shippers.

We continuously monitor this risk for both the short and longer term through dialogue and review with the third party pipelines and other market participants. Where available
and commercially appropriate given the production profile and commodity, we attempt to mitigate this risk by contracting for firm transportation capacity or using other means of
transportation.

Strategy Post 2010

We currently anticipate converting to a dividend paying corporation on or about January 1, 2011. We intend to take advantage of the SIFT conversion rules
to significantly simplify our underlying organization structure in 2010. Our corporate conversion is expected to be achieved through a Plan of Arrangement which must be approved by our Board of
Directors as well as our unitholders through a special meeting currently anticipated to be held in late 2010. There is a risk that our unitholders may not approve our conversion to a corporation,
however the Canadian government has legislated the SIFT tax beginning in 2011 which effectively removes the benefits of remaining a trust. There is also a risk that conversion could create a taxable
event for some unitholders.

We do not expect the conversion to a corporation to have a major impact on our underlying operating strategy or business affairs. Furthermore, at this time we do not anticipate
that the conversion will create a taxable event for our unitholders. However, going forward, the tax treatment of our distributions or dividends may be different for our unitholders/shareholders
depending on their jurisdiction and whether they are holding their investment in a taxable account or tax-deferred account.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY29

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Regulatory Risk & Greenhouse Gas Emissions

Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and operational impact on us. As an oil
and gas producer, we are subject to a broad range of regulatory requirements that continue to increase both within Canada and the United States.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas by participating in industry organizations, conferences, exchanging
information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results. In 2009 we continued with our extensive review of
the regulatory compliance obligations across our full business in all jurisdictions in order to confirm that we both understand and are meeting all requirements, and that employees are aware of their
individual accountabilities.

Specifically
with respect to regulations for the reduction of greenhouse gas emissions, the Canadian federal government did not issue the expected regulations in 2009, but rather continues to seek to
align with any regulations to be issued by the United States. Accordingly, while we continue to prepare to meet the potential requirements, the actual cost impact and its materiality to our
business remains uncertain.

Production Replacement 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 resources and developing existing reserves and resources. Acquisitions of oil and gas assets depend on our assessment of value at the time of acquisition. Incorrect assessments of value may
adversely affect distributions to unitholders and the value of our trust units.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions are approved by the Board of Directors and
where appropriate, independent reserve engineer evaluations are obtained.

Health, Safety and Environmental Risk ("HSE")

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

We have established a HSE Management System designed to:

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 potential losses from business interruption. HSE risks are reviewed regularly by the HSE committee which is comprised of members of the Board of Directors
and management.

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as most of our senior unsecured notes are denominated in U.S. dollars. Our U.S. operations are
directly exposed to fluctuations in the U.S. dollar when translated to our Canadian dollar denominated financial statements.

We
also have indirect exposure to fluctuations in foreign currency as our crude oil sales and a portion of our natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are
positively impacted as the Canadian dollar weakens relative to the U.S. dollar.

We have hedged our foreign currency exposure on both our US$175 million and US$54 million senior unsecured notes using financial swaps that convert the
U.S. denominated debt to Canadian dollar debt. In addition we have hedged the U.S. dollar interest obligation on our US$175 million notes. We have not entered into any other
foreign currency derivatives with respect to our oil and gas sales, our U.S. operations or the U.S. senior unsecured notes issued during 2009.

Interest Rate Exposure

We have exposure to movements in interest rates and credit markets as changing interest rates affect our borrowing costs and the unit price of yield-based
investments such as our trust units as well as other equity investments.

30      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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We monitor the interest rate forward market and have fixed the interest rate on approximately 77% of our debt through our senior unsecured notes and interest rate swaps. Our
bank credit facility which is based on floating interest rates was undrawn at year end.

Non-Resident Ownership and Mutual Fund Trust Status

Based on information received from our transfer agent and financial intermediaries in February 2010, we estimated our non-Canadian ownership
to be 69%. 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.

We currently meet 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. At this time, we do not anticipate any legislative changes that would affect our status as a mutual
fund trust.

2010 GUIDANCE

A summary of our 2010 guidance is below which does not include any potential acquisitions or divestments:

|Summary of 2010 Expectations                 |  | Target                                                  |  | Comments                                                                                                              | 
|-------------------------------------------- |  | ------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------- | 
|                                            
|Average annual production                    |  | 86,000 BOE/day                                          |  |                                                                                                                       | 
|Exit rate 2010 production                    |  | 88,000 BOE/day                                          |  | Assumes $425 million development capital spending, net of $33 million of Alberta DRC credits                          | 
|2010 production mix                          |  | 57% gas, 43% liquids                                    |  |                                                                                                                       | 
|Average royalty rate                         |  | 20%                                                     |  | Percentage of gross sales                                                                                             | 
|Operating costs                              |  | $10.90/BOE                                              |  |                                                                                                                       | 
|G&A costs                                    |  | $2.45/BOE                                               |  | Includes non-cash charges of $0.20/BOE (trust unit rights incentive plan)                                             | 
|U.S. income and withholding tax  cash costs |  | 5%                                                      |  | Applied to net cash flow generated by U.S. operations                                                                 | 
|Average interest and financing costs         |  | 8%                                                      |  | Based on current fixed rate contracts, forward interest rates and anticipated credit facility renewal costs           | 
|Corporate conversion and simplification      |  | $3 million or $0.10/BOE                                 |  | Fees related to our conversion from a trust to a corporation and simplification of our underlying corporate structure | 
|Development capital spending                 |  | $425 million, net of Alberta DRC credits of $33 million |  | Within the context of current commodity prices                                                                        | 
|Marcellus carry commitment                   |  | $64 million                                             |  | Will be reported as a property acquisition                                                                            | 
|                                            

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

Under the supervision of our Chief Executive Officer and Chief Financial Officer we have evaluated the effectiveness of our disclosure controls and procedures
and internal control over financial reporting as defined in Rule 13a  15 under the US securities Exchange Act of 1934 and as defined in Canada by National
Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. We have concluded that as of the end of the period covered by this report, our disclosure
controls and procedures and internal control over financial reporting are effective. There were no changes in our internal control over financial reporting during the period beginning on
October 1, 2009 and ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY31

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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, on the EDGAR website at www.sec.gov and at www.enerplus.com.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "budget", "strategy" and similar
expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements
pertaining to the following: asset dispositions and the use of proceeds therefrom; our corporate strategy, including transition from an income trust to a corporate form, the timing thereof and the
potential tax treatment of the conversion; expected oil, natural gas and natural gas liquids production volumes and product mix; future oil and natural gas prices and the Fund's commodity risk
management programs; cash flow sensitivities to commodity price, production, foreign exchange and interest rate changes; expected operating, G&A and trust conversion expenses and royalty and interest
rates; development capital expenditures and the allocation thereof; future acquisitions; receipt of required regulatory approvals; the amount of future abandonment and reclamation costs and asset
retirement obligations; taxes payable by the Fund and its subsidiaries; the tax pools of the Fund and its subsidiaries; renewal of our credit facility and the borrowing costs associated with the
credit facility; credit risk mitigation programs; future debt levels, financial capacity, liquidity and capital resources; cash distributions and dividends and the tax treatment thereof; future
contractual commitments; our transition to IFRS and the impact of that change on our financial results; reliance on industry partners to develop and expand our assets and operations; litigation
relating to our Marcellus properties and the potential outcome of such litigation; and future environmental obligations and the costs associated therewith.

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of the Fund including, without
limitation: that the Fund will conduct its operations in a manner consistent with its expectations and, where applicable, consistent with past practice; the general continuance of current or, where
applicable, assumed industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the
estimates of the Fund's reserve and resource volumes; certain commodity price and other cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to fund its
capital and operating requirements as needed; and the extent of its liabilities. The Fund believes the material factors, expectations and assumptions reflected in the forward-looking information and
statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking information and statements included in this MD&A
are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or
supply of the Fund's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans the
Fund or by third party operators of the Fund's properties, increased debt levels or debt service requirements; inaccurate estimation of the Fund's oil and gas reserve and resource volumes; limited,
unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; and certain other risks detailed
from time to time in the Fund's public disclosure documents (including, without limitation, those risks and contingencies described above and under "Risk Factors and Risk Management" in this MD&A and
under "Risk Factors" in the Fund's Annual Information Form dated March 13, 2009, which is available on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com and which forms
part of our Form 40-F filed with the SEC on March 13, 2009 and available at www.sec.gov. Additional risk factors will be contained in the Fund's Annual Information Form
(and corresponding Form 40-F) for the year ended December 31, 2009, which the Fund anticipates will be filed in mid-March 2010.

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of the Fund or its subsidiaries assumes any obligation to
publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

32      ENERPLUS RESOURCES2009 FINANCIAL
SUMMARY

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