EXHIBIT 99.3

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md&a

|
|

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

The following discussion and analysis of financial results is dated February 25, 2009 and is to be read in conjunction with the audited consolidated
financial statements as at and for the years ended December 31, 2008 and 2007. 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. In addition to disclosing reserves under the requirements of NI 51-101, we also disclose our
reserves on a company interest basis which is not a term defined under NI 51-101. This information may not be comparable to similar measures presented by other issuers. 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.

NON-GAAP MEASURES

Throughout the MD&A we use the term "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 are measures prescribed by GAAP which appear on our consolidated statements of
cash flows. The term "payout ratio" does 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 on cash flow, cash distributions and payout ratio.

2008 OVERVIEW

We began 2008 with the largest acquisition in our 23 year history. Focus Energy Trust ("Focus") was acquired on February 13, 2008 for approximately
$1.7 billion and added approximately 18,000 BOE/day of average daily production to our 2008 operating results. Commodity prices started the year off strong and continued to rise
throughout the first half of the year, ultimately peaking in July. Higher commodity prices combined with additional production volumes from Focus resulted in our cash flow from operating activities
totaling $1,262.8 million, representing a 45% increase from 2007.

On
July 31, 2008, as commodity prices began to decline, we reduced our exposure to oil sands and successfully disposed of our interest in the Joslyn oil sands lease ("Joslyn") for net proceeds
of $502.0 million. The proceeds were used to pay down debt and, as a result, we believe that we have one of the strongest balance sheets in the sector with a trailing twelve month
debt-to-cash flow ratio of 0.5x at December 31, 2008. We believe we are in a strong position given the current market conditions and expect to enhance our asset base
with opportunistic acquisitions.

In
addition to our successful acquisition and disposition activities, we completed the largest development capital spending program in our history with total spending of approximately
$577.7 million, resulting in the drilling of 643 net wells with a 99% success rate.

The
sharp decline in commodity prices in the fourth quarter of 2008 has focused our priorities on preserving our balance sheet strength and, as a result, we have decreased our 2009 development capital
program along with our monthly distributions. We intend to manage our capital spending and distributions to unitholders at a level which will minimize increases in our debt levels outside of any
acquisition activity. We have decided to limit spending on our current properties as we expect the acquisition market will provide the best opportunity to add quality reserves at a reasonable cost in
today's credit constrained environment. As a result of our reduced development capital spending, we expect annual production to average 91,000 BOE/day with an exit production rate of
88,000 BOE/day in 2009.

4      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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RESULTS OF OPERATIONS

Production

Production during 2008 averaged 95,687 BOE/day, essentially in line with our guidance of 96,000 BOE/day and 16% higher than 82,319 BOE/day
in 2007. The increase compared to 2007 was primarily due to the additional production volumes from the Focus assets which were purchased on February 13, 2008. Although our annual average
production approximated our guidance we did encounter challenges with production throughout the year. We experienced unplanned downtime at several non-operated facilities along with
setbacks executing our capital program due to weather and tie in delays while we assessed alternative well completion techniques.

Average
production during the year was weighted 59% to natural gas and 41% to liquids on a BOE basis. Average production volumes for the years ended December 31, 2008 and 2007 are
outlined below:

|Daily Production Volumes       |  | 2008    |  |  | 2007    |  | % Change | 
|------------------------------ |  | ------- |  |  | ------- |  | -------- | 
|                               |  |        
|Natural gas (Mcf/day)          |  | 338,869 |  |  | 262,254 |  | 29%      | 
|Crude oil (bbls/day)           |  | 34,581  |  |  | 34,506  |  | %       | 
|Natural gas liquids (bbls/day) |  | 4,627   |  |  | 4,104   |  | 13%      | 
|Total daily sales (BOE/day)    |  | 95,687  |  |  | 82,319  |  | 16%      | 
|                               |  |        

During the month of December we experienced production interruptions of approximately 1,600 BOE/day on two of our properties. We experienced an
interruption of 1,100 BOE/day related to a labour strike at a non-operated facility which processes our Tommy Lakes production and another interruption of 500 BOE/day related
to unscheduled downtime at Bantry. As a result, our December average daily production was approximately 96,400 BOE/day. Both of these issues were resolved and production was restored resulting
in an adjusted exit rate of approximately 98,000 BOE/day which was 500 BOE/day less than our guidance of 98,500 BOE/day.

Considering
our reduced development capital program in 2009, we expect 2009 annual production volumes to average 91,000 BOE/day, weighted 58% to natural gas and 42% to liquids. We expect to
exit 2009 with production of approximately 88,000 BOE/day. This guidance 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 2008 with those of 2007. It also compares the benchmark price indices for the same periods.

|Average Selling Price(1)      |  |   | 2008  |  |  |   | 2007  |  | % Change | 
|----------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                              |  |  
|Natural gas (per Mcf)         |  | $ | 8.17  |  |  | $ | 6.45  |  | 27%      | 
|Crude oil (per bbl)           |  | $ | 91.31 |  |  | $ | 65.11 |  | 40%      | 
|Natural gas liquids (per bbl) |  | $ | 68.93 |  |  | $ | 51.35 |  | 34%      | 
|Per BOE                       |  | $ | 65.79 |  |  | $ | 50.48 |  | 30%      | 
|                              |  |  

|Average Benchmark Pricing                                         |  |   | 2008   |  |  |   | 2007  |  | % Change | 
|----------------------------------------------------------------- |  | - | ------ |  |  | - | ----- |  | -------- | 
|                                                                  |  |  
|AECO natural gas  monthly index (CDN$/Mcf)                       |  | $ | 8.13   |  |  | $ | 6.61  |  | 23%      | 
|AECO natural gas  daily index (CDN$/Mcf)                         |  | $ | 8.14   |  |  | $ | 6.45  |  | 26%      | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                   |  | $ | 8.93   |  |  | $ | 6.92  |  | 29%      | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf) |  | $ | 9.50   |  |  | $ | 7.44  |  | 28%      | 
|WTI crude oil (US$/bbl)                                           |  | $ | 99.65  |  |  | $ | 72.34 |  | 38%      | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                         |  | $ | 106.01 |  |  | $ | 77.78 |  | 36%      | 
|CDN$/US$ exchange rate                                            |  |   | 0.94   |  |  |   | 0.93  |  | 1%       | 
|                                                                  |  |  

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY5

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Natural Gas

Natural gas prices in Alberta were strong through the first half of 2008, opening at $6.97/Mcf at AECO and rising steadily to a high of $11.82/Mcf by the end of
June. The strength in natural gas prices was partly fueled by the crude oil market which hit record levels by mid-year. Also, the key consuming regions of the U.S. experienced cold
weather from late January to March 2008 which decreased inventories to the lowest levels since 2004. Early forecasts for an active hurricane season and the expectation for supply disruptions
led to further price strength at the start of summer combined with demand in Asia and Europe for liquefied natural gas ("LNG") which diverted the majority of LNG supply away from North America,
ultimately helped keep prices high.

By
mid-year the market started to adjust to the impact of the increased U.S. shale gas production that had been brought on-stream throughout the year and gas inventories
started to rise despite a warmer than average summer. The impact of the global economic crisis began to take its toll on demand as supply additions continued to overwhelm the shrinking demand for gas.
Prices declined to a low of $5.79/Mcf at AECO at the end of September and closed the year at $6.34/Mcf.

During
2008 we sold approximately 84% of our natural gas on the AECO index split evenly between the daily and monthly indices and the remaining 16% against the monthly NYMEX index. During 2008 we sold
our natural gas for an average price of $8.17/Mcf (net of transportation costs), an increase of 27% from $6.45/Mcf realized in 2007. This increase is comparable to the price increases realized
in the AECO daily and monthly indices and the NYMEX monthly index.

Monthly Natural Gas Prices

GRAPHIC

Crude Oil

Crude prices were strong through the first two quarters of 2008 reaching a peak of US$147.27/bbl during July. Prices then dropped significantly, approximately
77% through the second half of the year. The global economic crisis and reduced access to credit began to weaken gasoline and distillate demand. Inventories began to grow and the general bearish mood
in the market, which was supported by continued weak economic data, pushed prices down reaching a low for the year in mid-December at US$33.87/bbl.

Our
crude oil production in 2008 was weighted 76% light/medium and 24% heavy. The average price received for our crude oil (net of transportation costs) was $91.31/bbl during 2008, a 40%
increase over 2007. The West Texas Intermediate ("WTI") crude oil benchmark price, after adjusting for the change in the U.S. dollar exchange rate, increased 36%
year-over-year. With gasoline demand falling and heavy oil refining capacity increasing, the demand for heavy oil increased. This fundamental change created a narrowing of the
heavy differentials which benefited our heavy crude pricing in comparison to the benchmark.

6      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Monthly Crude Oil Prices

GRAPHIC

Foreign Exchange

During the first half of the year the Canadian dollar fluctuated around par relative to the U.S. dollar, but by the third quarter it started to weaken
along with crude oil prices and by the fourth quarter it dropped dramatically reaching a low CDN$/US$ exchange rate of 0.77. As most of our crude oil and a portion of our natural gas sales are priced
in reference to U.S. dollar denominated benchmarks, this movement in the exchange rate during the latter part of the year increased the Canadian dollar prices we 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 upfront and potential costs of our risk management program as we seek to limit our exposure to price downturns. Hedge
positions for any given term are transacted across a range of prices and time.

Our
existing commodity contracts are designed to protect a portion of our natural gas sales through October 2010 and a portion of our crude oil sales through December 2009. We have also
hedged a portion of our electricity consumption through December 2010 to protect against rising electricity costs in the Alberta power market. See Note 12 for a detailed list of our
current price risk management positions.

The
following is a summary of the financial contracts in place at February 18, 2009 expressed as a percentage of our forecasted net production volumes:

|                                         |  | Natural Gas (CDN$/Mcf) |                                  | Crude Oil (US$/bbl)
|---------------------------------------- |  | ---------------------- | -------------------------------- | -------------------
|                                         |  |                        | January 1, 2009 
March 31, 2009 |                    
|                                         |  |                       
|Purchased Puts (floor prices)            |  | $                      | 9.20                             |                    
|%                                        |  |                        | 21%                              |                    
|Sold Puts (limiting downside protection) |  | $                      | 6.93                             |                    
|%                                        |  |                        | 14%                              |                    
|Swaps (fixed price)                      |  | $                      | 9.35                             |                    
|%                                        |  |                        | 3%                               |                    
|Sold Calls (capped price)                |  | $                      | 11.60                            |                    
|%                                        |  |                        | 10%                              |                    
|                                         |  |                       

Based on weighted average price (before premiums), estimated average annual production of 91,000 BOE/day, net of royalties and assuming a 18%
royalty rate.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY7

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Accounting for Price Risk Management

For the first three quarters of 2008 commodity prices were generally above our swap and sold call positions, resulting in cash losses of $135.0 million on
our natural gas and crude oil contracts for the period ending September 30, 2008. In the fourth quarter of 2008 commodity prices declined significantly to levels below our swap and purchased
put positions resulting in cash gains of $31.8 million on our natural gas and crude oil contracts. In aggregate we recorded net cash losses of $20.1 million on our natural gas contracts
and $83.1 million on our crude oil contracts in 2008. In comparison, during 2007 our commodity price risk management program resulted in cash gains of $23.6 million on our natural gas
contracts and cash losses of $10.0 million on our crude oil contracts.

At
December 31, 2008 the fair value of our natural gas and crude oil derivative instruments, net of premiums, represented a gain of $24.3 million and $96.6 million respectively.
These gains are recorded as current deferred financial assets on our balance sheet. In comparison, at December 31, 2007 the fair value of our natural gas derivative instruments, net of
premiums, represented a gain of $9.7 million which was recorded on our balance sheet as a deferred financial asset and the fair value of our crude oil derivative instruments, net of premiums,
represented a loss of $52.5 million which was recorded on our balance sheet as a deferred financial credit. The change in the fair value of our financial contracts during the year, after
adjusting for the Focus derivative instruments, resulted in unrealized gains of $16.2 million for natural gas and $153.4 million for crude oil. As the forward markets for natural gas and
crude oil fluctuate, new contracts are executed and existing contracts are realized, the changes in fair value will be reflected as a non-cash charge or non-cash gain in
earnings. See Note 12 for details.

The
following table summarizes the effects of our financial contracts on income for the years ended December 31, 2008 and 2007.

|Risk Management Costs($ millions, except per unit amounts) |                                    |   | 2008   |       |   |            | 2007       | 
|---------------------------------------------------------- | ---------------------------------- | - | ------ | ----- | - | ---------- | ---------- | 
|                                                           |                                    |  
|Cash (losses)/gains:                                       |                                    |   |        |       |   |            |            | 
|                                                           | Natural gas                        |   | $      | (20.1 | ) | $          | (0.16)/Mcf | 
|                                                           | Crude oil                          |   |        | (83.1 | ) | $          | (6.57)/bbl | 
|                                                           |                                    |   |        |       |   |            |            | 
|Total cash (losses)/gains                                  |                                    | $ | (103.2 | )     | $ | (2.94)/BOE |            | 
|Non-cash gains/ (losses) on financial contracts:           |                                    |   |        |       |   |            |            | 
|                                                           | Change in fair value  natural gas |   | $      | 16.2  |   | $          | 0.13/Mcf   | 
|                                                           | Change in fair value  crude oil   |   |        | 153.4 |   | $          | 12.12/bbl  | 
|                                                           |                                    |   |        |       |   |            |            | 
|Total non-cash gains/(losses)                              |                                    | $ | 169.6  |       | $ | 4.84/BOE   |            | 
|                                                           |                                    |   |        |       |   |            |            | 
|Total gains/(losses)                                       |                                    | $ | 66.4   |       | $ | 1.90/BOE   |            | 
|                                                           |                                    |  

Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts as listed in Note 12 and are based on forward markets as at February 18, 2009. 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                                          |  |   | Effect on 2009
Cash Flow
per Trust Unit(1) | 
|---------------------------------------------------------- |  | - | ------------------------------------------ | 
|                                                          
|Change of $0.50 per Mcf in the price of AECO natural gas   |  | $ | 0.20                                       | 
|Change of US$5.00 per barrel in the price of WTI crude oil |  | $ | 0.32                                       | 
|Change of 1,000 BOE/day in production                      |  | $ | 0.06                                       | 
|Change of $0.01 in the US$/CDN$ exchange rate              |  | $ | 0.08                                       | 
|Change of 1% in interest rate                              |  | $ | 0.04                                       | 
|                                                          

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.

8      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Revenues

Crude oil and natural gas revenues in 2008 were $2,304.2 million ($2,331.9 million, net of $27.7 million of transportation costs), an
increase of 52% or $787.1 million compared to $1,517.1 million ($1,539.2 million, net of $22.1 million of transportation costs) during 2007. Higher commodity prices and
production resulting primarily from our Focus acquisition helped to increase revenues significantly over 2007 levels.

|Analysis of Sales Revenue(1)($ millions) |  |   | Crude oil |  |   | NGLs  |  |   | Natural Gas |  |   | Total   | 
|---------------------------------------- |  | - | --------- |  | - | ----- |  | - | ----------- |  | - | ------- | 
|                                        
|2007 Sales Revenue                       |  | $ | 820.1     |  | $ | 76.9  |  | $ | 620.1       |  | $ | 1,517.1 | 
|Price variance(1)                        |  |   | 331.6     |  |   | 29.7  |  |   | 221.2       |  |   | 582.5   | 
|Volume variance                          |  |   | 4.0       |  |   | 10.1  |  |   | 190.5       |  |   | 204.6   | 
|                                        
|2008 Sales Revenue                       |  | $ | 1,155.7   |  | $ | 116.7 |  | $ | 1,031.8     |  | $ | 2,304.2 | 
|                                        

Other Income

Other income during 2008 was $8.5 million compared to $15.0 million in 2007. During 2008 we realized a gain of $8.3 million on the sale of
marketable securities and business interruption insurance proceeds of $8.9 million related to the Giltedge fire. In addition we recorded a write down of $10.0 million related to one of
our equity investments in a private company. In 2007 we had a gain of $14.1 million on the sale of marketable securities.

Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Total royalties paid during 2008 increased to $429.9 million
compared to $285.1 million in 2007 due to increased commodity prices and production volumes. As a percentage of oil and gas sales, net of transportation costs, royalties remained at
approximately 19%.

On
January 1, 2009 a new royalty regime came into effect in the province of Alberta where approximately 60% of our production is located. This new regime has provisions for escalating royalty
rates depending on production and product price levels. The fundamental design of this regime (which increases royalty rates as commodity prices increase) has removed some of the price upside
producers had previously factored into their risk assessments for capital investment. The Alberta government further modified the new regime with programs to encourage the drilling of medium and
deeper wells but with our reduced development capital spending plans we expect no material impact in 2009 from these modifications. Assuming current forward commodity prices and our production
profile, we expect our average royalty rate to decrease slightly in 2009. The following is a summary of our estimated corporate average royalty rates under various commodity price scenarios.

|2009 Royalty Rate                           |  |   |       |  |   |       |  |   |       |  |   |       |  |   |       |  |   |        |  |   |        | 
|------------------------------------------- |  | - | ----- |  | - | ----- |  | - | ----- |  | - | ----- |  | - | ----- |  | - | ------ |  | - | ------ | 
|                                           
|Light Crude Oil (Cdn $/bbl)(1)              |  | $ | 40.00 |  | $ | 50.00 |  | $ | 60.00 |  | $ | 70.00 |  | $ | 80.00 |  | $ | 100.00 |  | $ | 120.00 | 
|AECO Natural Gas ($/Mcf)                    |  | $ | 4.00  |  | $ | 5.00  |  | $ | 6.00  |  | $ | 7.00  |  | $ | 8.00  |  | $ | 10.00  |  | $ | 12.00  | 
|                                           
|Corporate royalty rate                      |  |   | 15.6% |  |   | 17.2% |  |   | 18.7% |  |   | 20.2% |  |   | 21.5% |  |   | 24.0%  |  |   | 25.9%  | 
|Incremental Annual Royalties(2)($ Millions) |  | $ | -28.6 |  | $ | -18.0 |  | $ | -0.1  |  | $ | +25.0 |  | $ | +53.3 |  | $ | +123.8 |  | $ | +203.1 | 
|                                           

Operating Expenses

Operating expenses during 2008 were $9.50/BOE or $332.6 million which was in-line with our guidance and 4% higher than 2007 operating costs of
$9.12/BOE or $274.2 million. Although we expected the acquisition of Focus to decrease operating costs on a BOE basis, rising costs due to high industry activity for most of 2008 resulted in
higher than expected charges for repairs and maintenance, chemicals, labour and supplies. In addition we increased our service rig activity related to our U.S. optimization program.

For
2009 we expect operating costs to average $10.65/BOE, representing an increase of 12% per BOE compared to 2008. Approximately half of this increase is due to lower production while the remainder
is due to increased power and regulatory costs as well as optimization efforts on our Canadian properties.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY9

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General and Administrative Expenses ("G&A")

G&A expenses were $1.88/BOE or $65.7 million during 2008, approximately 6% lower than our guidance of $2.00/BOE and 17% lower than $2.26/BOE in 2007. G&A
expenses were lower than our guidance primarily due to lower than anticipated compensation charges. All our compensation plans impact cash G&A with the exception of our trust unit rights incentive
plan which is non-cash.

Our
2008 G&A expenses included non-cash charges for our trust unit rights incentive plan of $7.0 million or $0.20/BOE compared to $8.4 million or $0.28/BOE for 2007. These
amounts relate solely to our trust unit rights incentive plan and are based on the fair value which is determined on the grant date using a binomial lattice option-pricing model. These values may not
represent the amount realized by employees. See Note 10 for further details.

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

|General and Administrative Costs($ millions) |  |   | 2008 |  |  |   | 2007 | 
|-------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                             |  |  
|Cash                                         |  | $ | 58.7 |  |  | $ | 59.5 | 
|Trust unit rights incentive plan (non-cash)  |  |   | 7.0  |  |  |   | 8.4  | 
|                                             |  |  
|Total G&A                                    |  | $ | 65.7 |  |  | $ | 67.9 | 
|                                             |  |  

|
|

|(Per BOE)                                   |  |   | 2008 |  |  |   | 2007 | 
|------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                            |  |  
|Cash                                        |  | $ | 1.68 |  |  | $ | 1.98 | 
|Trust unit rights incentive plan (non-cash) |  |   | 0.20 |  |  |   | 0.28 | 
|                                            |  |  
|Total G&A                                   |  | $ | 1.88 |  |  | $ | 2.26 | 
|                                            |  |  

Our 2008 cash G&A costs were significantly impacted by the drop in our trust unit price during the year. Our compensation plans are directly tied to the movement
in our trust unit price. During 2008 our trust unit price decreased 40% from $39.87 to $23.96 which significantly reduced the projected payouts on our plans and our 2008 G&A per BOE measure. In 2009
we expect cash G&A costs to be $2.25/BOE which is more consistent with 2007 levels adjusted for increased technical staff added and additional office space acquired during 2008. We expect total G&A
costs in 2009 to be $2.45/BOE including non-cash G&A costs of approximately $0.20/BOE.

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 8 for further
details.

Interest
on long-term debt during 2008 totaled $42.6 million, a $0.7 million increase from $41.9 million in 2007. This increase is due to higher average indebtedness
offset by lower interest rates year-over-year. As a result of the Focus acquisition in February 2008, $330.9 million of additional debt was assumed when the
average interest rate was approximately 4.5%. In
July 2008 we used the proceeds of $502.0 million from the disposition of Joslyn to reduce debt outstanding. The Bank of Canada interest rates declined through 2008 from 4.25% to 1.50% at
the end of the year. During 2008 our weighted average interest rate was 3.8% compared to 4.8% in 2007.

For
the year ended December 31, 2008 we recorded unrealized gains of $18.4 million compared to $8.3 million in 2007. The changes in the fair value of our interest rate swaps and
CCIRS that result from movements in forward market interest rates cause non-cash interest to fluctuate between periods.

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

|Interest Expense($ millions) |  |   | 2008  |   |  |  |   | 2007 |   | 
|---------------------------- |  | - | ----- | - |  |  | - | ---- | - | 
|                             |  |  
|Interest on long-term debt   |  | $ | 42.6  |   |  |  | $ | 41.9 |   | 
|Unrealized gain              |  |   | (18.4 | ) |  |  |   | (8.3 | ) | 
|                             |  |  
|Total Interest Expense       |  | $ | 24.2  |   |  |  | $ | 33.6 |   | 
|                             |  |  

10      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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At December 31, 2008 approximately 28% of our debt was based on fixed interest rates while 72% had floating interest rates. In comparison, at
December 31, 2007 approximately 18% of our debt was based on fixed interest rates and 82% was floating.

Capital Expenditures

During 2008 we spent $577.7 million on development capital, which was $190.5 million or 49% greater than 2007. The increased capital spending in
2008 was due to our expanded asset base resulting from the Focus acquisition as well as increased spending on shallow gas, deep gas and Bakken oil projects given higher commodity prices for the
majority of the year. Included in our development capital spending was $54.8 million of exploratory drilling, seismic and undeveloped land acquisitions mainly within the Montney and Bakken
plays which we expect to provide future development opportunities. We achieved a 99% success rate drilling 643 net wells during 2008.

Our
2008 development capital was approximately $33.0 million above our guidance of $545.0 million, mainly due to $22.0 million of accelerated activity in the Tommy Lakes, Bantry
and Shackleton areas. The remaining $11.0 million related to cost overages on various properties including pipeline maintenance at Golden and drilling costs at Pembina and Virden. We expect the
impact on production and overall capital spending for 2009 to be minimal.

Corporate
acquisitions for 2008 totaled approximately $1.7 billion and relate to the Focus acquisition which closed February 13, 2008 (refer to Note 5 for further details).
Property dispositions were $504.8 million during 2008 compared to $9.6 million in 2007. Our 2008 divestments relate mainly to the Joslyn disposition which closed in July 2008 for
net proceeds of $502.0 million. Our 2007 divestments included $5.6 million of property interests in the Thorhild area and the sale of undeveloped land in North Dakota for approximately
$3.6 million.

Property
acquisitions were $15.3 million during 2008 compared to $274.2 million in 2007. The majority of our 2007 acquisitions related to the purchase of our Kirby Oil Sands Project
("Kirby") for total consideration of $203.1 million and the purchase of gross-overriding royalty interests in the Jonah area for approximately $61.0 million.

|Capital Expenditures($ millions)                         |                      |   | 2008    |         |  |  |   | 2007  |       | 
|-------------------------------------------------------- | -------------------- | - | ------- | ------- |  |  | - | ----- | ----- | 
|                                                         |                      |  
|Development expenditures                                 |                      | $ | 442.4   |         |  |  | $ | 321.3 |       | 
|Plant and facilities                                     |                      |   | 135.3   |         |  |  |   | 65.9  |       | 
|                                                         |                      |  
|Development Capital                                      |                      |   | 577.7   |         |  |  |   | 387.2 |       | 
|Office                                                   |                      |   | 10.6    |         |  |  |   | 6.5   |       | 
|                                                         |                      |  
|Sub-total                                                |                      |   | 588.3   |         |  |  |   | 393.7 |       | 
|Property acquisitions(1)                                 |                      |   | 15.3    |         |  |  |   | 274.2 |       | 
|Corporate acquisitions                                   |                      |   | 1,757.5 |         |  |  |   |      |       | 
|                                                         |                      |  
|                                                         | Capital Expenditures |   |         | 2,361.1 |  |  |   |       | 667.9 | 
|                                                         |                      |  
|Property dispositions(1)                                 |                      |   | (504.8  | )       |  |  |   | (9.6  | )     | 
|                                                         |                      |  
|Total Net Capital Expenditures                           |                      | $ | 1,856.3 |         |  |  | $ | 658.3 |       | 
|                                                         |                      |  
|Total Capital Expenditures financed with cash flow       |                      | $ | 476.7   |         |  |  | $ | 221.7 |       | 
|Total Capital Expenditures financed with debt and equity |                      |   | 1,379.6 |         |  |  |   | 443.2 |       | 
|Total non-cash consideration for property dispositions   |                      |   |        |         |  |  |   | (6.6  | )     | 
|                                                         |                      |  
|Total Net Capital Expenditures                           |                      | $ | 1,856.3 |         |  |  | $ | 658.3 |       | 
|                                                         |                      |  

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY11

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The following is a summary by play type of our development capital expenditures during 2008 and 2007, as well as our current expectations for 2009.

|Play type($ millions)          |  |   | 2009 Estimate |  |   | 2008  |  |  |   | 2007  | 
|------------------------------ |  | - | ------------- |  | - | ----- |  |  | - | ----- | 
|                               |  |  
|Shallow Gas and CBM            |  | $ | 74.3          |  | $ | 159.1 |  |  | $ | 39.3  | 
|Crude Oil Waterfloods          |  |   | 45.4          |  |   | 84.0  |  |  |   | 54.2  | 
|Tight Gas                      |  |   | 78.4          |  |   | 81.0  |  |  |   | 34.7  | 
|Bakken/Tight Oil               |  |   | 41.8          |  |   | 99.0  |  |  |   | 106.2 | 
|Other Conventional Oil and Gas |  |   | 35.1          |  |   | 103.4 |  |  |   | 113.9 | 
|Oil Sands                      |  |   | 25.0          |  |   | 51.2  |  |  |   | 38.9  | 
|                               |  |  
|Total                          |  | $ | 300.0         |  | $ | 577.7 |  |  | $ | 387.2 | 
|                               |  |  

We expect development capital expenditures in 2009 to be approximately $300 million including oil sands development capital of approximately
$25 million and $50 million on initial resource investments (land and seismic) neither of which are expected to impact 2009 production.

Oil Sands

Our current oil sands portfolio includes the 100% owned and operated Kirby steam assisted gravity drainage ("SAGD") project and a 12% minority equity ownership
interest in Laricina Energy Ltd., a private oil sands company focused on SAGD development in the Athabasca oil sands.

Our
Kirby project has not commenced commercial production. As a result, all associated costs inclusive of acquisition expenditures are capitalized and excluded from our depletion calculation. During
2008 we capitalized costs of $40.6 million associated with the Kirby project including costs of our regulatory application, which we filed on September 26, 2008. At December 31,
2008 capitalized costs life-to-date for our oil sands development were $257.6 million compared to $321.8 million at December 31, 2007. Included in the 2007
amount was our Joslyn interest which we sold on July 31, 2008.

As
a result of current low crude oil prices we have reduced our 2009 capital spending on the Kirby project to $25.0 million consisting primarily of engineering and regulatory costs associated
with advancing Phase I and seismic costs aimed at expanding the overall resource base associated with this lease. Kirby has a reserve life of over 25 years and we believe over the
longer term oil prices will recover to justify proceeding with development. Our regulatory application is currently under review and we expect to receive regulatory approval by the end of 2009. Our
board of directors will re-evaluate whether to continue to proceed with or delay the Kirby project at that time.

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 2008
DDA&A was $640.4 million or $18.29/BOE compared to $463.7 million or $15.43/BOE in 2007. The increase is a result of higher PP&E and production from the Focus acquisition.

No
impairment of the Fund's PP&E values existed at December 31, 2008 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 $634.0 million arose as 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.

Accounting
standards require the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate the balance might be impaired. If such
impairment exists, it would be charged to income in the period in which the impairment occurs. No goodwill impairment exists as of December 31, 2008.

12      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Asset Retirement Obligations

We have estimated our future asset retirement obligations based on our net ownership interest in wells and facilities, along with the estimated cost and timing
to abandon and reclaim wells and facilities in the future. Our asset retirement obligation was $207.4 million at December 31, 2008 compared to $165.7 million at
December 31, 2007. The majority of the $41.7 million increase was due to the addition of abandonment obligations associated with the Focus acquisition. The remainder of the increase was
due to additional costs from development capital activity and accretion expense offset by retirement costs incurred. See Note 4 for further details.

The
following chart shows the amortization of the asset retirement cost and accretion of the asset retirement obligation compared to asset retirement obligations settled.

|($ millions)                                 |  |   | 2008 |  |  |   | 2007 | 
|-------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                             |  |  
|Amortization of the asset retirement cost    |  | $ | 20.0 |  |  | $ | 11.4 | 
|Accretion of the asset retirement obligation |  |   | 11.9 |  |  |   | 6.7  | 
|                                             |  |  
|Total Amortization and Accretion             |  | $ | 31.9 |  |  | $ | 18.1 | 
|                                             |  |  
|Asset Retirement Obligations Settled         |  | $ | 18.3 |  |  | $ | 16.3 | 
|                                             |  |  

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 2039 and 2048. 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

Canadian Government's tax changes

In 2008, the Canadian Federal government introduced draft tax legislation that allowed for the conversion of a specified investment flow-through
("SIFT") entity into corporate form on a tax deferred basis, defined the provincial tax component of the SIFT tax, and accelerated the recognition of the "Safe Harbour" limit. None of the above were
enacted prior to the prorogation of Parliament in December 2008. Therefore, all bills containing the draft legislation have lapsed.

Subsequent
to the year end, the Federal government has introduced draft tax legislation which includes the above mentioned measures as part of Canada's Economic Action Plan. When or if this draft tax
legislation becomes substantially enacted, Enerplus will be able to recognize the tax benefit associated with the lower provincial tax component of the SIFT tax.

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 2008 was $51.2 million compared to $1.0 million in 2007. The change was due to the following:

After
consideration of the above items the future tax provisions were comparable between periods.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY13

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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. However, effective January 1, 2011 we will be subject to the SIFT tax should we
remain a trust.

A
Canadian income tax liability of $24.3 million was triggered on the acquisition of Focus in 2008. This liability was included in Focus' assumed working capital at the time of acquisition. We
have accrued for the recovery of these taxes in 2008 which constitutes the majority of the Canadian income tax recovery.

During
2008 our U.S. operations incurred current taxes in the amount of $47.8 million compared to $23.0 million in 2007. The increase is due to higher net income combined with a
modest decrease in drilling and completion 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. Our
U.S. taxes as a percentage of cash flow, assuming constant working capital, were 18% in 2008 compared to our guidance of 20% as a result of lower commodity prices in the fourth quarter. We
expect current income and withholding taxes to average approximately 15% of cash flow from U.S. operations in 2009 based on our current development capital program and assuming all funds are
repatriated to Canada.

Tax Pools

We estimate our tax pools at December 31, 2008 to be as follows:

|Pool Type($ millions) |  |   | Trust |  |   | Operating entities |  |   | Total | 
|--------------------- |  | - | ----- |  | - | ------------------ |  | - | ----- | 
|                     
|COGPE                 |  | $ | 470   |  | $ | 165                |  | $ | 635   | 
|CDE                   |  |   |      |  |   | 670                |  |   | 670   | 
|UCC                   |  |   |      |  |   | 680                |  |   | 680   | 
|CEE                   |  |   |      |  |   | 125                |  |   | 125   | 
|Tax losses and other  |  |   | 15    |  |   | 380                |  |   | 395   | 
|Foreign tax pools     |  |   |      |  |   | 210                |  |   | 210   | 
|                     
|Total                 |  | $ | 485   |  | $ | 2,230              |  | $ | 2,715 | 
|                     

Net Income

Net income in 2008 was $888.9 million or $5.54 per trust unit compared to $339.7 million or $2.66 per trust unit in 2007. The $549.2 million
increase in net income was primarily due to a $787.0 million increase in oil and gas sales (net of transportation costs), $119.3 million increase in commodity derivative
instrument gains and a $48.3 million increase in future tax recovery, partially offset by increased DDA&A charges of $176.7 million, increased royalty expense of $144.8 million
and increased operating costs of $58.4 million.

Cash Flow from Operating Activities

Cash flow from operating activities in 2008 was $1,262.8 million or $7.86 per trust unit compared to $868.5 million or $6.80 per trust unit in
2007. The increase is primarily due to increased commodity prices in the first three quarters of 2008 and higher production volumes.

14      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Selected Financial Results

|                                                    |  | Year ended December 31, 2008 |                     | Year ended December 31, 2007
|--------------------------------------------------- |  | ---------------------------- | ------------------- | ----------------------------
|Per BOE of production (6:1)                         |  |                              | Operating
Cash
Flow | (1)                         
|                                                    |  |                             
|Production per day                                  |  |                              |                     |                             
|                                                    |  |                             
|Weighted average sales price(2)                     |  | $                            | 65.79               |                             
|Royalties                                           |  |                              | (12.27              | )                           
|Commodity derivative instruments                    |  |                              | (2.94               | )                           
|Operating costs                                     |  |                              | (9.51               | )                           
|General and administrative                          |  |                              | (1.68               | )                           
|Interest expense, net of interest income            |  |                              | (0.91               | )                           
|Foreign exchange gain/(loss)                        |  |                              | (0.68               | )                           
|Current income tax                                  |  |                              | (0.65               | )                           
|Restoration and abandonment cash costs              |  |                              | (0.52               | )                           
|Depletion, depreciation, amortization and accretion |  |                              |                    |                             
|Future income tax (expense)/recovery                |  |                              |                    |                             
|Other Income                                        |  |                              |                    |                             
|                                                    |  |                             
|Total per BOE                                       |  | $                            | 36.63               |                             
|                                                    |  |                             

Selected Annual Canadian and U.S. Financial Results

The following table provides a geographical analysis of key operating and financial results for 2008 and 2007.

|                                                    |                                              | Year ended December 31, 2008 |        | Year ended December 31, 2007
|--------------------------------------------------- | -------------------------------------------- | ---------------------------- | ------ | ----------------------------
|(CDN$ millions, except per unit amounts)            |                                              |                              | Canada |                             
|                                                    |                                              |                             
|Average Daily Production Volumes                    |                                              |                              |        |                             
|                                                    | Natural gas (Mcf/day)                        |                              |        | 326,138                     
|                                                    | Crude oil (bbls/day)                         |                              |        | 25,248                      
|                                                    | Natural gas liquids (bbls/day)               |                              |        | 4,627                       
|                                                    | Total daily sales (BOE/day)                  |                              |        | 84,232                      
|Pricing(1)                                          |                                              |                              |        |                             
|                                                    | Natural gas (per Mcf)                        |                              | $      | 8.14                        
|                                                    | Crude oil (per bbl)                          |                              | $      | 90.28                       
|                                                    | Natural gas liquids (per bbl)                |                              | $      | 68.93                       
|Capital Expenditures                                |                                              |                              |        |                             
|                                                    | Development capital and office               |                              | $      | 518.2                       
|                                                    | Acquisitions of oil and gas properties       |                              | $      | 15.2                        
|                                                    | Corporate Acquisitions                       |                              | $      | 1,757.5                     
|                                                    | Dispositions of oil and gas properties       |                              | $      | (504.9                      
|Revenues                                            |                                              |                              |        |                             
|                                                    | Oil and gas sales(1)                         |                              | $      | 1,941.2                     
|                                                    | Royalties                                    |                              | $      | (351.9                      
|                                                    | Commodity derivative instruments gain/(loss) |                              | $      | 66.4                        
|Expenses                                            |                                              |                              |        |                             
|                                                    | Operating                                    |                              | $      | 314.5                       
|                                                    | General and administrative                   |                              | $      | 58.6                        
|Depletion, depreciation, amortization and accretion |                                              | $                            | 550.0  |                             
|Current income taxes (recovery)/expense             |                                              | $                            | (25.1  | )                           
|                                                    |                                              |                             

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY15

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Three Year Summary of Key Measures

Overall, increased production volumes from our Focus acquisition and increased commodity prices have resulted in higher oil and gas sales, net income and cash
flow from operating activities during 2008 compared to 2007. The rise in crude oil prices during 2006, 2007 and the first three quarters of 2008 contributed to higher overall sales, however gas sales
moderated in 2007 as a result of lower natural gas prices. The following table provides a summary of net income, cash flow and other key measures.

|($ millions, except per unit amounts) |  |   | 2008    |  |  |   | 2007    |  |   | 2006    | 
|------------------------------------- |  | - | ------- |  |  | - | ------- |  | - | ------- | 
|                                      |  |  
|Oil and gas sales(1)                  |  | $ | 2,304.2 |  |  | $ | 1,517.1 |  | $ | 1,572.7 | 
|Net income                            |  |   | 888.9   |  |  |   | 339.7   |  |   | 544.8   | 
|Per unit (Basic)(2)                   |  |   | 5.54    |  |  |   | 2.66    |  |   | 4.48    | 
|Per unit (Diluted)                    |  |   | 5.53    |  |  |   | 2.66    |  |   | 4.47    | 
|Cash flow from operating activities   |  |   | 1,262.8 |  |  |   | 868.5   |  |   | 863.7   | 
|Per unit (Basic)(2)                   |  |   | 7.86    |  |  |   | 6.80    |  |   | 7.10    | 
|Cash distributions                    |  |   | 786.1   |  |  |   | 646.8   |  |   | 614.3   | 
|Per unit (Basic)(2)                   |  |   | 4.90    |  |  |   | 5.07    |  |   | 5.05    | 
|Payout ratio                          |  |   | 62%     |  |  |   | 74%     |  |   | 71%     | 
|Total assets                          |  |   | 6,230.1 |  |  |   | 4,303.1 |  |   | 4,203.8 | 
|Long-term debt, net of cash           |  |   | 657.4   |  |  |   | 725.0   |  |   | 679.7   | 
|                                      |  |  

Liquidity and Capital Resources

Capital Markets and Enerplus' Credit Exposure

The recent turmoil in the financial markets has impacted the availability of credit and equity in the marketplace. The current market conditions indicate that it
may be difficult to issue additional equity or increase credit capacity without significant costs at this time. In addition, there has been a dramatic reduction in crude oil and natural gas prices
since the summer of 2008. As a result there has been a greater emphasis on
evaluating credit capacity, credit counterparties and liquidity. We have discussed these risks as they relate to our credit facility, oil and gas sales counterparties, financial derivative
counterparties and joint venture partners below.

Credit Facility

Enerplus' bank credit facility is an unsecured, covenant-based credit agreement with a syndicate of thirteen financial institutions, a summary 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 Enerplus' facility, seven are major Canadian banks which represent
approximately $1.025 billion or 73% of the commitments under the $1.4 billion facility. The facility is extendable each year and is currently set to expire in November 2010. Rates
under the facility range between 55.0 and 110.0 basis points over bankers' acceptance rates and are significantly lower than rates currently being negotiated in the marketplace. At
December 31, 2008 we have drawn $380.9 million or approximately 27% of our $1.4 billion facility and have a trailing debt-to-cash flow ratio of 0.5x. Our
borrowing cost is currently 55.0 basis points over bankers' acceptance rates.

At
December 31, 2008 Enerplus was in compliance with all covenants under the credit facility. Our exposure to our lenders relates to their potential inability to fund. Should a lender be unable
or choose not to fund, other lenders have the right, but not the obligation, to increase their commitment levels to cover the shortfall. Failure to fund would be considered a breach of contract and
could result in potential damages in favour of Enerplus, however the likelihood of substantiating and receiving damages is unknown. We have not experienced any funding issues under the facility
to date.

16      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Oil and Gas Sales Counterparties

The Fund's 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 completed for both our oil and gas sales
counterparties as well as our financial derivative counterparties. For the year ended December 31, 2008 we have made a $1.5 million bad debt provision, the majority of which relates to
our exposure to a Canadian subsidiary of SemGroup L.P., which is currently subject to insolvency proceedings in the U.S.

Financial Derivative Counterparties

The Fund is exposed to credit risk in the event of non-performance by our financial counterparties regarding our derivative contracts. The Fund
mitigates this risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have no exposure to Lehman Brothers, which is currently
in insolvency proceedings. We have International Swaps and Derivatives Association ("ISDA") agreements in place with the majority of our financial counterparties. These agreements provide some credit
protection in that they generally allow 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. Absent an
ISDA we rely on long form confirmations which provide Enerplus with similar credit protection in terms of aggregating transactions and netting for settlement in the case of a credit event. At
December 31, 2008 we had $128.1 million in mark-to-market assets offset by $26.4 million of mark-to-market liabilities consisting
of net asset positions of $77.2 million with major Canadian institutions and $24.5 million with U.S. institutions.

We
will continue to monitor developments in the financial markets that could impact the credit worthiness of our financial counterparties, however it has recently been very difficult to foresee
counterparty solvency issues. 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 fully drawn bank facilities. We do not
anticipate any significant issues in the collection of our joint interest receivables at this time. However, if the current low commodity prices and tight capital markets prevail, there is a risk of
increased bad debts related to our industry partners, and as a result we have increased our bad debt provision by $1.0 million.

Distribution Policy

The amount of cash distributions 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 has historically varied between approximately 10% and 40% of annual cash flow from
operating activities 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.

The
sharp decrease in crude oil and natural gas prices has resulted in a decrease in our overall cash flows. This commodity price downturn, combined with the ongoing uncertainty and reduced access to
the debt and equity markets, has reinforced our belief in the importance of maintaining strong financial flexibility. To that end, we have reduced our monthly cash distributions three times during the
last five months to the current level of $0.18 per unit effective February 20, 2009. We intend to manage our distribution levels and capital spending in order to minimize increases in our debt
levels and preserve our balance sheet strength for future acquisitions.

Although
we intend to continue to make cash distributions to our unitholders, these distributions are not guaranteed. To the extent there is taxable income at the trust level, determined in accordance
with the Canadian Income Tax Act, the distribution of that taxable income is non-discretionary.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY17

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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 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
2009 development capital spending is expected to be $300 million which represents a 48% decrease from 2008 spending of $577.7 million. In 2009 we expect to spend $50 million
on initial resource investments such as land acquisitions and seismic to position us for development opportunities in the future, which is not expected to add production in 2009. As a result we expect
our production to decrease to an annual average of 91,000 BOE/day and an exit rate of 88,000 BOE/day in 2009. At this level of capital spending it will be difficult to replace our
production without reliance on acquisitions to supplement our reserves.

Enerplus
currently has approximately $9.5 billion of safe harbour growth capacity within the context of the Canadian Government's "normal growth" guidelines for SIFT's. This amount is
calculated in reference to the combined market capitalizations of Enerplus and Focus on October 31, 2006 and also includes equity that may be issued to replace existing debt of both entities at
that time.

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 2008 cash distributions of
$786.1 million were funded entirely through cash flow of $1,262.8 million. Our payout ratio, which is calculated as cash distributions divided by cash flow, was 62% for 2008 compared to
74% in 2007. See "Non-GAAP Measures" in this MD&A.

In
aggregate, our 2008 cash distributions of $786.1 million and our development capital and office expenditures of $588.3 million totaled $1,374.4 million, or approximately 109%
of our cash flow of $1,262.8 million. We expect to support our distributions and capital expenditures with our cash flow, however we will continue to fund acquisitions and growth through
additional debt and equity when required. We anticipate that our reduced capital spending plans for 2009 along with our reductions in monthly cash distributions will help minimize any increases in
debt levels and preserve our balance sheet. There will be years when we are investing capital in opportunities that do not immediately generate cash flow (such as our Kirby oil sands project) where we
may also use debt and equity to support the investment. Despite our 2008 cash flow being less than the aggregate of our cash distributions and development capital, we continue to have conservative
debt levels with a trailing twelve month debt-to-cash flow ratio of 0.5x at December 31, 2008 and an annualized fourth quarter 2008 debt-to-cash
flow ratio of 0.7x.

For
the year ended December 31, 2008 our net income exceeded our cash distributions by $102.8 million whereas in 2007 our cash distributions exceeded our net income by
$307.1 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
impact cash flow from operations. In addition, 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 costs of our PP&E and not the fair market value of replacing those assets within the context of the current environment.

It
is not possible 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.

18      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

---



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

|($ millions, except per unit amounts)                    |  |   | 2008    |  |  |   | 2007   |   |   | 2006  |   | 
|-------------------------------------------------------- |  | - | ------- |  |  | - | ------ | - | - | ----- | - | 
|                                                         |  |  
|Cash flow from operating activities                      |  | $ | 1,262.8 |  |  | $ | 868.5  |   | $ | 863.7 |   | 
|Cash Distributions                                       |  |   | 786.1   |  |  |   | 646.8  |   |   | 614.3 |   | 
|                                                         |  |  
|Excess of cash flow over cash distributions              |  | $ | 476.7   |  |  | $ | 221.7  |   | $ | 249.4 |   | 
|Net income                                               |  | $ | 888.9   |  |  | $ | 339.7  |   | $ | 544.8 |   | 
|Excess/(shortfall) of net income over cash distributions |  | $ | 102.8   |  |  | $ | (307.1 | ) | $ | (69.5 | ) | 
|Cash distributions per weighted average trust unit       |  | $ | 4.90    |  |  | $ | 5.07   |   | $ | 5.05  |   | 
|Payout ratio(1)                                          |  |   | 62%     |  |  |   | 74%    |   |   | 71%   |   | 
|                                                         |  |  

Asset Retirement Costs

Actual asset retirement costs incurred in the period are deducted for the purposes of calculating cash flow. Differences between actual asset retirement costs
incurred and the amortization and accretion of the asset retirement obligation are discussed in the Asset Retirement Obligations section of this MD&A and Note 4.

Long-Term Debt

Long-term debt at December 31, 2008 was $664.3 million, a decrease of $62.4 million from $726.7 million at
December 31, 2007. Long-term debt at December 31, 2008 was comprised of $380.9 million of bank indebtedness and $283.4 million of senior unsecured notes. Our
bank indebtedness decreased by $116.5 million year-over-year mainly due to proceeds received from the Joslyn disposition of $502.0 million which was partially
offset by additional debt of $330.9 million acquired in the Focus acquisition. Our senior unsecured notes are comprised of our US$175 million senior notes and our US$54 million
senior notes. The change in period end foreign exchange rate resulted in an increase in the carrying value of our senior notes to $283.4 million compared to $229.3 million at
December 31, 2007.

Our
working capital, excluding cash, at December 31, 2008 increased $147.2 million compared to December 31, 2007 primarily due to an increase in our deferred financial assets
relating to our financial derivative contracts. Excluding deferred financial assets and credits, our working capital decreased by $16.4 million compared to the prior year. This is primarily due
to an increase in future income taxes payable offset slightly by a decrease in distributions payable and an increase in accounts receivable.

We
continue to maintain a conservative balance sheet as demonstrated below with over $1.0 billion in unused credit capacity under our current facility:

|Financial Leverage and Coverage                       |  | Year ended Dec. 31, 2008 |  |  | Year ended Dec. 31, 2007 | 
|----------------------------------------------------- |  | ------------------------ |  |  | ------------------------ | 
|                                                      |  |                         
|Long-term debt to trailing 12 month cash flow         |  | 0.5 x                    |  |  | 0.8 x                    | 
|Long-term debt to annualized fourth quarter cash flow |  | 0.7 x                    |  |  | 0.9 x                    | 
|Cash flow to interest expense (12 month trailing)     |  | 46.5 x                   |  |  | 25.8 x                   | 
|Long-term debt to long-term debt plus equity          |  | 13%                      |  |  | 22%                      | 
|                                                      |  |                         

Long-term debt is measured net of cash.

At December 31, 2008 Enerplus had a $1.4 billion unsecured covenant based term bank facility maturing November 2010, through its wholly-
owned subsidiary EnerMark Inc. We have the ability to extend the facility each year or repay the entire balance at the end of the term. Due to the volatility in the credit markets we chose not
to extend the term of the credit facility this year. The facility carries floating interest rates that we expect to range between 55.0 and 110.0 basis points over bankers' acceptance rates,
depending on Enerplus' ratio of senior debt to earnings before interest, taxes and non-cash items.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY19

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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, 2008 we were in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing cash flow including acquisition cash
flows. Refer to "Debt of Enerplus" in our Annual Information Form for the year ended December 31, 2008 for a detailed description of these covenants.

Principal
payments on Enerplus' senior unsecured notes are required commencing in 2010 and are more fully discussed below under "Commitments" and Note 13.

We
continue to have adequate liquidity to fund planned development capital spending for 2009 through a combination of cash flow retained by the business and debt, if needed.

Commitments

We have contracted to transport 143 MMcf/day of natural gas on the TransCanada system in Alberta, 70 MMcf/day on TransGas in Saskatchewan,
48 MMcf/day in B.C. via Spectra, as well as 9 MMcf/day on the Alliance pipeline to the U.S. Midwest.

Our
gas supply dedicated to aggregator sales contracts will decline in 2009 to approximately 6% of gas production (22.0 MMcf/day), down from more than 20% in 2008. The early truncation of the
ProGas and Cargill aggregator pools leaves Pan-Alberta as the only remaining aggregator. 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 2,480 bbls/day of crude oil from field locations to suitable marketing sales points within western Canada.

Our
Canadian and U.S. office leases expire in 2014 and 2011 respectively. Annual costs of these lease commitments include rent and operating fees. The Fund's commitments, contingencies and
guarantees are more fully described in Note 13.

As
at December 31, 2008 Enerplus has the following minimum annual commitments including long-term debt:

|                             |  |   |       |  |  | Minimum Annual Commitment Each Year |      |  | Total Committed |      
|---------------------------- |  | - | ----- |  |  | ----------------------------------- | ---- |  | --------------- | -----
|($ millions)                 |  |   | Total |  |  |                                     | 2009 |  |                 | 2010 
|                             |  |  
|Bank credit facility(1)      |  | $ | 380.9 |  |  | $                                   |     |  | $               | 380.9
|Senior unsecured notes(1)(2) |  |   | 323.2 |  |  |                                     |     |  |                 | 53.7 
|Pipeline commitments         |  |   | 62.7  |  |  |                                     | 18.8 |  |                 | 11.8 
|Processing commitments       |  |   | 25.6  |  |  |                                     | 7.6  |  |                 | 7.7  
|Office leases                |  |   | 69.6  |  |  |                                     | 8.7  |  |                 | 11.7 
|                             |  |  
|Total commitments(3)         |  | $ | 862.0 |  |  | $                                   | 35.1 |  | $               | 465.8
|                             |  |  

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

We had 165,590,000 trust units outstanding at December 31, 2008 compared to 129,813,000 trust units outstanding at
December 31, 2007.

20      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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Included
in the December 31, 2008 outstanding units were 30,150,000 units issued on February 13, 2008 to acquire Focus. In addition 9,087,000 exchangeable partnership units
were assumed on the Focus acquisition which became exchangeable into Enerplus trust units at the ratio of 0.425 of a trust unit for each partnership unit. During 2008 1,849,000 partnership
units were converted into 786,000 trust units, leaving 7,238,000 partnership units outstanding at December 31, 2008 representing the equivalent of
3,076,000 trust units.

In
addition 1,881,000 trust units (2007  1,307,000) 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 $70.5 million (2007  $56.8 million) of additional equity to
the Fund. For further details see Note 10.

The
weighted average basic number of trust units outstanding during 2008 was 160,589,000 compared to 127,691,000 trust units during 2007. At February 20, 2009 we had
165,707,000 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 the 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.

We
paid $4.89 per trust unit in cash distributions to unitholders on record during 2008. For Canadian tax purposes, approximately 2% of these distributions, or $0.08 per trust unit was a tax deferred
return of capital, approximately 98% or $4.81 per trust unit was taxable to unitholders as other income, and there was no eligible dividend income.

For
2009, 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 were 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 in 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$4.77 per trust unit to U.S. residents during the 2008 calendar year of which 8% or US$0.38 per trust unit was a tax deferred return of capital and 92% or US$4.39 per unit was a
taxable qualified dividend.

For
2009, 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.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY21

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Quarterly Financial Information

In general, crude oil and natural gas sales increased from 2007 to mid 2008 due to increased production and increased commodity prices. Oil and gas sales
decreased during the second half of 2008 as a result of the sharp decline in commodity prices.

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 rate reductions. Furthermore, changes in the fair value of our commodity derivative instruments and other financial instruments cause net income to continually fluctuate between
quarters.

Quarterly Financial Information

|                                               |  |   | Oil and   |     |   |            |  | Net Income Per Trust Unit
|---------------------------------------------- |  | - | --------- | --- | - | ---------- |  | -------------------------
|(CDN$ millions, except per trust unit amounts) |  |   | Gas Sales | (1) |   | Net Income |  |                          
|                                              
|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      |  | $                        
|                                              
|2007                                           |  |   |           |     |   |            |  |                          
|Fourth Quarter                                 |  | $ | 389.8     |     | $ | 98.7       |  | $                        
|Third Quarter                                  |  |   | 364.8     |     |   | 93.0       |  |                          
|Second Quarter                                 |  |   | 382.5     |     |   | 40.1       |  |                          
|First Quarter                                  |  |   | 380.0     |     |   | 107.9      |  |                          
|                                               |  |   |           |     |   |            | 
|Total                                          |  | $ | 1,517.1   |     | $ | 339.7      |  | $                        
|                                              

Summary Fourth Quarter Information

In comparing the fourth quarter of 2008 with the same period in 2007:

22      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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The
following tables provide an analysis of key financial and operating results for the three months ended December 31, 2008 and 2007.

|(CDN$ millions, except per unit amounts)                                       |  |   | Three Months Ended
December 31, 2008 |   |  |  |   | Three Months Ended
December 31, 2007 |   | 
|------------------------------------------------------------------------------ |  | - | ------------------------------------ | - |  |  | - | ------------------------------------ | - | 
|                                                                               |  |  
|Financial (000's)                                                              |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income                                                                     |  | $ | 189.5                                |   |  |  | $ | 98.7                                 |   | 
|Cash Flow from Operating Activities                                            |  | $ | 258.5                                |   |  |  | $ | 205.1                                |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 167.0                                |   |  |  | $ | 163.4                                |   | 
|Financial per Unit(2)                                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income                                                                     |  | $ | 1.15                                 |   |  |  | $ | 0.76                                 |   | 
|Cash Flow from Operating Activities                                            |  | $ | 1.56                                 |   |  |  | $ | 1.58                                 |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 1.01                                 |   |  |  | $ | 1.26                                 |   | 
|Payout Ratio(3)                                                                |  |   | 65%                                  |   |  |  |   | 80%                                  |   | 
|Average Daily Production                                                       |  |   | 97,702                               |   |  |  |   | 80,959                               |   | 
|Selected Financial Results per BOE(4)                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Oil and Gas Sales(5)                                                           |  | $ | 46.54                                |   |  |  | $ | 52.33                                |   | 
|Royalties                                                                      |  |   | (8.61                                | ) |  |  |   | (9.83                                | ) | 
|Commodity Derivative Instruments                                               |  |   | 3.54                                 |   |  |  |   | (0.08                                | ) | 
|Operating Costs                                                                |  |   | (9.46                                | ) |  |  |   | (8.53                                | ) | 
|General and Administrative                                                     |  |   | (1.71                                | ) |  |  |   | (1.94                                | ) | 
|Interest and Foreign Exchange                                                  |  |   | (2.73                                | ) |  |  |   | (1.70                                | ) | 
|Taxes                                                                          |  |   | 0.92                                 |   |  |  |   | (1.70                                | ) | 
|Restoration and Abandonment                                                    |  |   | (0.53                                | ) |  |  |   | (0.75                                | ) | 
|                                                                               |  |  
|Cash Flow from Operating Activities before changes in non-cash working capital |  | $ | 27.96                                |   |  |  | $ | 27.80                                |   | 
|                                                                               |  |  
|Weighted Average Number of Units Outstanding (thousands)                       |  |   | 165,373                              |   |  |  |   | 129,658                              |   | 
|Development Capital                                                            |  |   | 200.3                                |   |  |  |   | 106.1                                |   | 
|Net Wells Drilled                                                              |  |   | 174                                  |   |  |  |   | 76                                   |   | 
|Success Rate                                                                   |  |   | 99%                                  |   |  |  |   | 100%                                 |   | 
|Average Benchmark Pricing                                                      |  |   |                                      |   |  |  |   |                                      |   | 
|AECO natural gas  monthly index (CDN$/Mcf)                                    |  | $ | 6.79                                 |   |  |  | $ | 6.00                                 |   | 
|AECO natural gas  daily index (CDN$/Mcf)                                      |  | $ | 6.68                                 |   |  |  | $ | 6.14                                 |   | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                                |  | $ | 6.77                                 |   |  |  | $ | 7.03                                 |   | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf)              |  | $ | 8.26                                 |   |  |  | $ | 6.89                                 |   | 
|WTI crude oil (US$/bbl)                                                        |  | $ | 58.73                                |   |  |  | $ | 90.68                                |   | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                                      |  | $ | 71.62                                |   |  |  | $ | 88.90                                |   | 
|CDN$/US$ exchange rate                                                         |  |   | 0.82                                 |   |  |  |   | 1.02                                 |   | 
|                                                                               |  |  

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY23

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Selected Quarterly Canadian and U.S. Financial Results

|                                         |                                                     | Three months ended December 31, 2008 |        | Three months ended December 31, 2007
|---------------------------------------- | --------------------------------------------------- | ------------------------------------ | ------ | ------------------------------------
|(CDN$ millions, except per unit amounts) |                                                     |                                      | Canada |                                     
|                                         |                                                     |                                     
|Average Daily Production Volumes         |                                                     |                                      |        |                                     
|                                         | Natural gas (Mcf/day)                               |                                      |        | 333,046                             
|                                         | Crude oil (bbls/day)                                |                                      |        | 26,122                              
|                                         | Natural gas liquids (bbls/day)                      |                                      |        | 4,529                               
|                                         | Total daily sales (BOE/day)                         |                                      |        | 86,158                              
|Pricing(1)                               |                                                     |                                      |        |                                     
|                                         | Natural gas (per Mcf)                               |                                      | $      | 7.01                                
|                                         | Crude oil (per bbl)                                 |                                      | $      | 54.85                               
|                                         | Natural gas liquids (per bbl)                       |                                      | $      | 43.55                               
|Capital Expenditures                     |                                                     |                                      |        |                                     
|                                         | Development capital and office                      |                                      | $      | 186.7                               
|                                         | Acquisitions of oil and gas properties              |                                      | $      | 1.3                                 
|                                         | Dispositions of oil and gas properties              |                                      | $      | (0.2                                
|Revenues                                 |                                                     |                                      |        |                                     
|                                         | Oil and gas sales(1)                                |                                      | $      | 364.4                               
|                                         | Royalties                                           |                                      | $      | (65.8                               
|                                         | Commodity derivative instruments gain/(loss)        |                                      | $      | 161.2                               
|Expenses                                 |                                                     |                                      |        |                                     
|                                         | Operating                                           |                                      | $      | 80.0                                
|                                         | General and administrative                          |                                      | $      | 13.9                                
|                                         | Depletion, depreciation, amortization and accretion |                                      | $      | 142.9                               
|                                         | Current income taxes                                |                                      | $      | (8.2                                
|                                         |                                                     |                                     

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 15. 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 and is more focused on low risk development
drilling that has traditionally achieved high success rates.

Under
the full cost method of accounting, an impairment test is applied to the overall carrying value of property, plant and equipment, 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.

24      ENERPLUS RESOURCES2008 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 NI 51-101 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, especially in times of decreasing commodity prices and trust unit values.

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.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY25

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RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Current Year Accounting Changes

Effective January 1, 2008, the Fund adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants ("CICA"):
Handbook Section 1535, Capital Disclosures, Section 3862, Financial Instruments  Disclosures and Section 3863, Financial
Instruments  Presentation.

Capital Disclosures

Section 1535 establishes standards for disclosing information regarding an entity's capital and how it is managed.

Financial Instruments  Disclosures, Financial Instruments  Presentation

Sections 3862 and 3863 establish standards for enhancing financial statements users' understanding of the significance of financial instruments to
an entity's financial position, performance and cash flows. They require that entities provide disclosures regarding the nature
and extent of risks arising from financial instruments to which they are exposed both during the reporting period and at the balance sheet date, as well as how the entities manage those risks.

These
standards were adopted prospectively.

Future Accounting Changes

Goodwill and Intangible Assets

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other
Intangible Assets and Section 3450, Research and Development Costs. The new Section will be effective on January 1, 2009. Section 3064 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 Trust is currently evaluating the impact of the adoption of this new Section, however does not expect a material impact on its Consolidated Financial
Statements.

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

In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic plan that will result in Canadian GAAP being converged with IFRS by 2011 for public
reporting entities. On February 13, 2008 the AcSB confirmed that IFRS will be required for public companies beginning January 1, 2011.

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

To
date we have completed our IFRS diagnostic assessment and have started to analyze and identify accounting policy choices, which include assessing the impact on information systems and business
processes. We have also provided training to certain business groups which are impacted. We intend to generate financial information in accordance with IFRS during 2010 to provide comparative
information for the 2011 financial statements.

The
transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. As we have not yet determined 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 prior to
our adoption of IFRS, our plan is subject to change based on new facts and circumstances that arise after the date of this MD&A.

26      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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RISK FACTORS AND RISK MANAGEMENT

Commodity Price Risk

Enerplus' operating results and financial condition are dependent on the prices we receive for our crude oil and natural gas production. These prices 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 un-hedged. 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, and may be exposed to risk of default
by the counterparties. Refer to the "Price Risk Management" section.

Credit Facility Risk and Credit Exposure

Recent economic conditions have negatively affected the availability of credit and increased the risk that certain counterparties for our oil and gas sales,
financial derivatives, and our operating partners may fail to pay.

Enerplus has drawn only approximately 27% of its $1.4 billion bank credit facility at December 31, 2008. Also approximately 70% of the commitments under this
facility are represented by major Canadian banks which are considered to be among the most sound credit providers. When the time comes to renew our banking facility we expect to pay higher rates and
there is no guarantee that all our banks will renew at their current commitment levels.

There are normal credit risks with receivables associated with our product sales, derivative contracts, insurers and joint venture partners. We mitigate these risks through
diversification and review processes that assess and monitor our counterparties' credit worthiness on a regular basis. If the current low commodity prices and uncertain credit markets prevail there is
a risk of increasing bad debts.

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

Access to Capital Markets

Historically 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 the majority of our cash flow to our unitholders. Recently, with global capital markets in turmoil and the sharp decline in commodity prices, we have chosen to reduce our reliance on the
capital markets by balancing the level of capital spending and distributions more closely to our cash flow. Nonetheless, it will be difficult to pursue material acquisitions and value creation
opportunities without accessing the capital markets in the future. We expect the debt markets will recover but the cost of debt financing will increase and credit capacity may be tight for the next
few years. The equity capital markets are showing some signs of recovery however, equity issues are generally at higher discounts and smaller sizes than previously experienced. Equity market
receptivity depends in large part upon the market's expectation for oil and natural gas prices. Continued access to capital is also 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 maintain a prudent capital structure by retaining a portion of cash flow for capital spending and utilizing the equity markets 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 may increase the risk of write-downs for our oil and gas property investments. Regulatory changes to reporting practices
can also result in reserve or resource write-downs.

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We strive to acquire low risk properties with a high proportion of proved reserves, positive operating metrics, long reserve lives and predictable production. Similarly, we
generally participate in lower-risk development projects. If we do engage in exploration it is usually in areas where there is potential for larger scale 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.

Sproule Associates Limited ("Sproule") evaluated 93% of the total proved plus probable value (discounted at 10%) of our Canadian conventional year-end reserves, in
accordance with NI 51-101 and has reviewed the remainder of the reserves which Enerplus evaluated internally. Netherland, Sewell & Associates Inc. ("NSA") of Dallas,
Texas, evaluated 100% of the reserves attributed to our assets in the United States and utilized Sproule's forecast and constant price and cost assumptions as of December 31, 2008 to
maintain consistency. GLJ Petroleum Consultants Ltd. ("GLJ") evaluated the resources attributable to all our oil sands areas. The Reserves Committee of the Board of Directors has reviewed and
approved the reserve and resource reports of the independent evaluators.

Strategy Post 2010

We continue to evaluate alternatives to our income trust structure beyond 2010 in response to the Canadian Federal Government's plan to tax income trusts
effective January 1, 2011.

We
are currently hesitant to make structural changes for the next two years unless opportunities arise, as we believe this exemption period has value for our unitholders. Unless circumstances change
within the current capital markets or the regulatory, tax or political environment, we will most likely convert into a dividend paying corporation however, we are keeping our options open at
this time.

We
do not expect the conversion to a corporation to have a major impact on our underlying operating strategy or business affairs. We expect such a conversion can be achieved without creating a taxable
event for most 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.

After
2010, the applicable Canadian income tax rate at the entity level will be similar whether we remain a trust or convert to a corporation. The most important variables that will determine the
level of cash taxes incurred in a given year will be the price of crude oil and natural gas, capital spending and the amount of tax pools at the time of conversion.

With
the current forward market for commodity prices and our current plans with respect to production, costs and capital spending, we would not expect a significant change to our overall tax costs
until 2013 even if we were to convert to a corporation during 2010. Even after 2013 we expect our capital spending will help shelter taxes and would expect cash taxes to average around 15% of cash
flow, which is not dissimilar to other oil and gas production companies.

If
crude oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, our tax pools would be utilized more quickly and we may experience higher than
expected cash taxes.

We
must emphasize it is difficult to give guidance on future taxability as we operate within an industry that constantly changes given acquisitions, divestments, capital spending, distributions and
overall commodity prices.

Regulatory Risk

Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and operational impact on us. In the
province of Alberta a new royalty regime came into effect on January 1, 2009. The Canadian Federal Government enacted a new tax on publicly traded income trusts and limited partnerships, the
SIFT tax, effective January 1, 2011. In early 2008 the Canadian government presented a long term plan to reduce greenhouse gas emissions, with the intent of issuing draft regulations in the
fall of 2008. The draft regulations have been delayed as the federal government considers aligning its approach in this area with that of the new administration in the U.S. Accordingly the cost
impact to our business remains uncertain.

Our
operations expose us to possible regulatory changes and greater emphasis on regulatory requirements by both the Canadian and U.S. governments. As an oil and gas producer, we are subject to
a broad range of regulatory requirements. Similarly, as a mutual fund trust, we have a unique structure that is vulnerable to changes in legislation or income tax law.

28      ENERPLUS RESOURCES2008 FINANCIAL
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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 2008 we also initiated an extensive review of
the regulatory compliance obligations across our full business in all jurisdictions. We intend to complete this review in 2009.

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. We have reduced our capital spending plans dramatically for 2009 and this will make it difficult to replace our production without relying
on acquisitions. 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.

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. 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 with the third party pipelines and other market participants, as well as by review of
supply and demand studies prepared by third party experts. 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.

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 business interruption. HSE risks are reviewed regularly by the HSE committee comprised of members of the Board of Directors.

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as 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 our interest obligation on our US$175 million notes.

We have not entered into any other foreign currency derivatives with respect to oil and gas sales or our U.S. operations.

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY29

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Interest Rate Exposure

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

We monitor the interest rate forward market and have fixed the interest rate on approximately 28% of our debt through our senior unsecured notes and interest
rate swaps.

Non-Resident Ownership and Mutual Fund Trust Status

Based on information received from our transfer agent and financial intermediaries in February 2009, an estimated 65% of our outstanding trust units were
held by non-residents. 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.

Summary 2009 Outlook

Enerplus offers investors the benefits of owning a large, diversified portfolio of producing crude oil and natural gas properties within Canada and the
United States. As such, our business prospects are closely linked to the opportunities and challenges associated with oil and natural gas production. In particular, we are strongly influenced
by the price of crude oil and natural gas, both of which have been volatile in recent years. Our comments with respect to our 2009 outlook should be taken within the context of the current commodity
price environment.

The
following summarizes our 2009 guidance as provided throughout this MD&A. We do not attempt to forecast commodity prices and, as a result, we do not forecast future cash flow or cash distributions.
Readers are encouraged to apply their own price expectations to the following factors to arrive at an expected cash distribution.

|Summary of 2009 Expectations                 |  | Target               |  | Comments                                                                                                                                                  | 
|-------------------------------------------- |  | -------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------- | 
|                                            
|Average annual production                    |  | 91,000 BOE/day       |  | Does not include any further potential acquisitions/divestments                                                                                           | 
|Exit rate 2009 production                    |  | 88,000 BOE/day       |  | Assumes $300 million development capital spending                                                                                                         | 
|2009 production mix                          |  | 58% gas, 42% liquids |  |                                                                                                                                                           | 
|Average royalty rate                         |  | 18%                  |  | Percentage of gross sales                                                                                                                                 | 
|Operating costs                              |  | $10.65/BOE           |  |                                                                                                                                                           | 
|G&A costs                                    |  | $2.45/BOE            |  | Includes non-cash charges of $0.20/BOE (unit rights incentive plan)                                                                                       | 
|U.S. income and withholding tax  cash costs |  | 15%                  |  | Applied to net cash flow generated by U.S. operations and assumes repatriation of the funds to Canada after U.S. development capital spending             | 
|Average interest cost                        |  | 3%                   |  | Based on current fixed rate contracts and forward market                                                                                                  | 
|Payout ratio                                 |  | 50%  75%            |  | We intend to manage our distributions and capital spending in order to minimize increases in debt outside of acquisitions                                 | 
|Development capital spending                 |  | $300 million         |  | We intend to monitor commodity prices and cost structures and will adjust capital spending in order to minimize increases in debt outside of acquisitions | 
|                                            

30      ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY

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We believe it is important to maintain a conservative balance sheet as a defense against commodity price changes and to be positioned to capture acquisition
opportunities. As a result, we have reduced our 2009 development capital spending to $300 million, which is 48% lower than our 2008 spending. We have also reduced our monthly distributions to
unitholders to $0.18 per trust unit and based on current commodity prices we do not expect to materially increase our debt levels in 2009 outside of acquisition activities.

We
will continue to focus on low-risk development opportunities and review our risk management strategies in response to changing prices, the current economic environment and the economics
of our acquisition and development projects.

For
2009, we estimate that 95% of cash distributions will be taxable and 5% will be a tax-deferred return of capital for our Canadian unitholders. For our U.S. unitholders, we
estimate that 90% of cash distribution will be taxable and 10% will be a tax-deferred return of capital.

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, 2008 and ended on December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 management's discussion and analysis ("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" 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: the amount, timing and tax treatment of cash distributions to unitholders; payout ratios; tax treatment of income trusts such as the Fund; the structure of the Fund and
its subsidiaries; the Fund's income taxes, tax liabilities and tax pools; the volume and product mix of the Fund's oil and gas production; oil and natural gas prices and the Fund's risk management
programs; the amount of asset retirement obligations; future liquidity and financial capacity and resources; cost and expense estimates; results from operations and financial ratios; cash flow
sensitivities; royalty rates and their impact on the Fund's operations and results; future growth including development, exploration, and acquisition and development activities and related
expenditures, including with respect to both our conventional and oil sands activities.

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
continue to conduct its operations in a manner consistent with past operations; the general continuance of current or, where applicable, assumed industry conditions; availability of debt and/or equity
sources to fund the Fund's capital and operating requirements as needed; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the accuracy of the estimates of
the Fund's reserve volumes; and certain commodity price and other cost assumptions. The Fund believes the
material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable at this time 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:

ENERPLUS RESOURCES2008 FINANCIAL
SUMMARY31

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changes
in commodity prices; unanticipated operating results or production declines; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements;
inaccurate estimation of the Fund's oil and gas reserves volumes; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; 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 identified in this MD&A, and in
the Fund's Annual Information Form for the year ended December 31, 2008, copies of which are available on the Fund's SEDAR profile at www.sedar.com and which also form part of the Fund's
Form 40-F for the year ended December 31, 2008 filed with the SEC, a copy of which is available at www.sec.gov.

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.

This
report contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil
and Gas Evaluation Handbook as "those quantities of petroleum estimated, as of given date, to be potentially recoverable from known accumulations using established technology or technology under
development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political
and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early
evaluation stage." There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Enerplus will produce any portion of the volumes currently
classified as contingent resources. The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Kirby oil sands project as
reserves consist of current uncertainties around the specific scope and timing of the project development, proposed reliance on technologies that have not yet been demonstrated to be commercially
applicable in oil sands applications, the uncertainty regarding marketing plans for production from the subject areas and improved estimation of project costs. Based on current information and market
conditions, Enerplus believes that development of the Kirby project will proceed as described in this report. However, there are a number of inherent risks and contingencies associated with the
development of the project, including commodity price fluctuations, project costs, receipt of regulatory approvals and those other risks and contingencies described above and under "Risk Factors" in
the Fund's Annual Information Form for the year ended December 31, 2008, a copy of which is available on Enerplus' SEDAR profile at www.sedar.com, and which also forms part of Enerplus'
Form 40-F for the year ended December 31, 2008 filed with the SEC, a copy of which is available at www.sec.gov.

32      ENERPLUS RESOURCES2008 FINANCIAL
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