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 24, 2011 and is to be read in conjunction with the audited consolidated
financial statements as at and for the years ended December 31, 2010 and 2009. All amounts are stated in Canadian dollars unless otherwise specified. All references to GAAP refer to Canadian
generally accepted accounting principles. All note references relate to the notes included with the consolidated financial statements. In accordance with Canadian practice revenues are reported on a
gross basis, before deduction of Crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on
6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE
in isolation may be misleading.

These
financial statements and notes present the results of Enerplus Corporation (formerly Enerplus Resources Fund). On January 1, 2011, Enerplus Resources Fund (the "Fund") converted
from an income trust into a corporate entity with Enerplus Corporation being the successor issuer to the Fund. However, because the Fund, and not Enerplus Corporation, was the public reporting issuer
in existence on December 31, 2010, information in this MD&A and accompanying financial statements makes reference to the Fund and its outstanding trust units rather than Enerplus Corporation
and its common shares that are currently in existence.

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

NON-GAAP MEASURES

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

OVERVIEW

2010 was a transition year for Enerplus as we focused our asset base by investing over $1.0 billion in early stage growth plays and also disposed of
non-core conventional assets, including our Kirby oil sands lease, for approximately $900 million in total proceeds. Our disposition activity funded the majority of our acquisitions
allowing us to maintain a strong balance sheet throughout the year.

Our
annual average production was in-line with guidance at 83,139 BOE/day. Our capital spending totaled $542.7 million for the year, $27.7 million above guidance due
to additional costs in the Marcellus and lower Alberta Drilling Royalty Credits ("DRCs") than we had anticipated. We exited the year with production of 77,200 BOE/day, slightly below guidance
primarily due to delays with two significant wells at Fort Berthold which are now on stream and had average initial production rates of 1,500 bbls/day per well. Operating costs were better than
expected at $9.54/BOE while our general and administration ("G&A") expenses were in line with expectations at $2.60/BOE.

We
successfully completed our corporate conversion from Enerplus Resources Fund to Enerplus Corporation effective January 1, 2011. During 2010 we maintained monthly distributions of $0.18 per
trust unit. Going forward we intend to distribute a significant portion of our cash flow to investors through a monthly dividend and we expect to complement this dividend with annual growth in
production and reserves per share.

RESULTS OF OPERATIONS

Production

Production during 2010 averaged 83,139 BOE/day, in-line with our guidance of 83,000 to 84,000 BOE/day and 9% lower than
91,569 BOE/day in 2009. The decrease compared to 2009 was consistent with our expectations given the reduced capital program in 2009 and the sale of approximately 10,400 BOE/day of
non-core conventional oil and gas production during the year. Also, the majority of our acquisitions consisted of undeveloped land with minimal existing production.

ENERPLUS2010 FINANCIAL
SUMMARY5

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Average production in 2010 was weighted 58% to natural gas and 42% to crude oil and liquids on a BOE basis. Average production volumes for the years ended December 31, 2010 and 2009 are
outlined below:

|Daily Production Volumes       |  | 2010    |  |  | 2009    |  | % Change | 
|------------------------------ |  | ------- |  |  | ------- |  | -------- | 
|                               |  |        
|Natural gas (Mcf/day)          |  | 288,692 |  |  | 326,570 |  | (12)%    | 
|Crude oil (bbls/day)           |  | 31,135  |  |  | 32,984  |  | (6)%     | 
|Natural gas liquids (bbls/day) |  | 3,889   |  |  | 4,157   |  | (6)%     | 
|Total daily sales (BOE/day)    |  | 83,139  |  |  | 91,569  |  | (9)%     | 
|                               |  |        

Our average daily production for the month of December was approximately 77,200 BOE/day, below our anticipated exit rate of 80,000 to
82,000 BOE/day. The decrease was primarily due to delays in drilling and completing two Fort Berthold wells, as well as weather conditions in North Dakota which delayed our ability to truck
production to sales points.

We
expect 2011 production volumes to average 78,000 to 80,000 BOE/day, with an increased weighting of crude oil and liquids to approximately 47% of overall production. We expect our production
volumes to increase throughout the year exiting 2011 at approximately 80,000 to 84,000 BOE/day. This guidance does not contemplate any acquisitions or dispositions.

Pricing

As most of our crude oil and natural gas production is priced in reference to U.S. dollar denominated benchmarks, a stronger Canadian dollar decreases
the prices that we would have otherwise realized. 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 2010 with those of 2009. It also compares the benchmark price indices for the same periods.

|Average Selling Price(1)      |  |   | 2010  |  |  |   | 2009  |  | % Change | 
|----------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                              |  |  
|Natural gas (per Mcf)         |  | $ | 4.05  |  |  | $ | 3.91  |  | 4%       | 
|Crude oil (per bbl)           |  | $ | 70.38 |  |  | $ | 58.54 |  | 20%      | 
|Natural gas liquids (per bbl) |  | $ | 51.41 |  |  | $ | 41.54 |  | 24%      | 
|Per BOE                       |  | $ | 42.85 |  |  | $ | 36.89 |  | 16%      | 
|                              |  |  

|Average Benchmark Pricing                                         |  |   | 2010  |  |  |   | 2009  |  | % Change | 
|----------------------------------------------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                                                                  |  |  
|AECO natural gas  monthly index (CDN$/Mcf)                       |  | $ | 4.13  |  |  | $ | 4.14  |  | 0%       | 
|AECO natural gas  daily index (CDN$/Mcf)                         |  | $ | 4.00  |  |  | $ | 3.95  |  | 1%       | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                   |  | $ | 4.42  |  |  | $ | 4.03  |  | 10%      | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf) |  | $ | 4.56  |  |  | $ | 4.58  |  | 0%       | 
|WTI crude oil (US$/bbl)                                           |  | $ | 79.53 |  |  | $ | 61.80 |  | 29%      | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                         |  | $ | 81.99 |  |  | $ | 70.23 |  | 17%      | 
|US$/CDN$ exchange rate                                            |  |   | 0.97  |  |  |   | 0.88  |  | 10%      | 
|                                                                  |  |  

Natural Gas

Natural gas prices remained depressed through 2010 as the overall supply of gas continued to increase throughout the year outpacing any increase in demand. Gas
inventory levels were at record highs when we started the winter season. Even with the cold winter weather experienced in December, the daily AECO price averaged only $3.90/mcf.

During
2010 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 monthly U.S. based indices. During
2010 we sold our natural gas for an average price of $4.05/Mcf (net of transportation costs), an increase of 4% from $3.91/Mcf realized in 2009. This increase is generally in-line
with the changes experienced on the AECO and NYMEX indices.

6      ENERPLUS2010 FINANCIAL
SUMMARY

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Monthly Natural Gas Prices

GRAPHIC

Crude Oil

Crude oil prices increased throughout 2010 from an average WTI price of US$78.40/bbl in January to US$89.23/bbl in December 2010. Stabilization of the
global economy and forecasts of incremental demand helped support the oil price recovery. In the fourth quarter of 2010 prices rallied in response to a weaker U.S. dollar and strengthening
U.S. equity markets.

As
a portion of our oil production is sold in the U.S., we expect the change in our realized price to fall between the change in the U.S. and Canadian dollar equivalent benchmark WTI prices. The
average price received for our crude oil (net of transportation costs) was $70.38/bbl during 2010, a 20% increase over 2009. This was in-line with expectations as the WTI price,
after adjusting for the change in the US$/CDN$ dollar exchange rate, increased 17% year-over-year while the WTI price in U.S. dollars increased by 29%.

Monthly Crude Oil Prices

GRAPHIC

Price Risk Management

We continue to adjust our price risk management program with consideration given to our overall financial position together with the economics of our
development capital program and potential acquisitions. Consideration is also given to the costs of our risk management program as we seek to limit our exposure to price downturns. We have continued
to add crude oil hedge positions for 2011 and 2012 however we have been reluctant to add additional natural gas hedge positions due to the low forward price for natural gas. See Note 13 for a
detailed list of our current price risk management positions.

ENERPLUS2010 FINANCIAL
SUMMARY7

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The
following is a summary of the financial contracts in place at February 14, 2011 expressed as a percentage of our forecasted net production volumes:

|                                         |  | Natural Gas
(CDN$/Mcf) |                                  |  | Crude Oil
(US$/bbl)
|---------------------------------------- |  | ---------------------- | -------------------------------- |  | -------------------
|                                         |  |                        | January 1, 2011 
March 31, 2011 |  |                    
|                                         |  |                       
|Sold Puts (limiting downside protection) |  | $                      | 4.15                             |  |                    
|% of forecasted 2011 net production      |  |                        | 26%                              |  |                    
|Swaps (fixed price)                      |  | $                      | 6.39                             |  |                    
|% of forecasted 2011 net production      |  |                        | 33%                              |  |                    
|Purchased Calls (repurchasing upside)    |  | $                      | 6.48                             |  |                    
|% of forecasted 2011 net production      |  |                        | 26%                              |  |                    
|                                         |  |                       

Based on weighted average price (before premiums), estimated 2011 average annual production of 78,000 to 80,000 BOE/day,
net of royalties and assuming a 20% royalty rate.

Accounting for Price Risk Management

During 2010 our price risk management program generated cash gains of $67.3 million on our natural gas contracts and cash losses of $17.6 million
on our crude oil contracts. In comparison, in 2009 we experienced cash gains of $74.8 million and $81.0 million respectively. The cash gains in 2010 are due to contracts which provided
floor protection above market prices whereas the cash losses are a result of crude oil prices rising above our swap positions.

As
the forward markets for natural gas and crude oil fluctuate, new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash
charge or gain to earnings. At December 31, 2010 the fair value of our natural gas and crude oil derivative instruments, net of premiums, represented a gain of $12.6 million and loss of
$38.3 million respectively. The gain is recorded as a current deferred financial asset and the loss is recorded as a current deferred financial liability on our balance sheet. In
comparison, at December 31, 2009 the fair value of our natural gas and crude oil derivative instruments represented gains of $20.4 million and losses of $20.3 million
respectively. The change in the fair value of our commodity derivative instruments during 2010 resulted in unrealized losses of $7.7 million for natural gas and $18.0 million for crude
oil. See Note 13 for details.

The
following table summarizes the effects of our financial contracts on income for the years ended December 31, 2010 and 2009:

|Risk Management Costs($ millions, except per unit amounts) |                                    |   | 2010  |       |   |            | 2009       | 
|---------------------------------------------------------- | ---------------------------------- | - | ----- | ----- | - | ---------- | ---------- | 
|                                                           |                                    |  
|Cash gains/(losses):                                       |                                    |   |       |       |   |            |            | 
|                                                           | Natural gas                        |   | $     | 67.3  |   | $          | 0.64/Mcf   | 
|                                                           | Crude oil                          |   |       | (17.6 | ) | $          | (1.55)/bbl | 
|                                                           |                                    |   |       |       |   |            |            | 
|Total cash gains/(losses)                                  |                                    | $ | 49.7  |       | $ | 1.64/BOE   |            | 
|Non-cash gains/(losses) on financial contracts:            |                                    |   |       |       |   |            |            | 
|                                                           | Change in fair value  natural gas |   | $     | (7.7  | ) | $          | (0.07)/Mcf | 
|                                                           | Change in fair value  crude oil   |   |       | (18.0 | ) | $          | (1.58)/bbl | 
|                                                           |                                    |   |       |       |   |            |            | 
|Total non-cash gains/(losses)                              |                                    | $ | (25.7 | )     | $ | (0.85)/BOE |            | 
|                                                           |                                    |   |       |       |   |            |            | 
|Total gains/(losses)                                       |                                    | $ | 24.0  |       | $ | 0.79/BOE   |            | 
|                                                           |                                    |  

8      ENERPLUS2010 FINANCIAL
SUMMARY

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Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts as listed in Note 13 and are based on forward markets as at February 14, 2011. To
the extent the market price of crude oil and natural gas change significantly from current levels, the sensitivities will no longer be relevant as the effect of our commodity contracts
will change.

|Sensitivity Table                                          |  |   | Estimated
Effect on 2011
Cash Flow
per Trust Unit(1) | 
|---------------------------------------------------------- |  | - | ---------------------------------------------------- | 
|                                                          
|Change of $0.50 per Mcf in the price of AECO natural gas   |  | $ | 0.18                                                 | 
|Change of US$5.00 per barrel in the price of WTI crude oil |  | $ | 0.09                                                 | 
|Change of 1,000 BOE/day in production                      |  | $ | 0.08                                                 | 
|Change of $0.01 in the US$/CDN$ exchange rate              |  | $ | 0.06                                                 | 
|Change of 1% in interest rate                              |  | $ | 0.03                                                 | 
|                                                          

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

Revenues

Crude oil and natural gas revenues in 2010 were $1,300.2 million ($1,327.1 million, net of $26.9 million of transportation costs), an
increase of 5% compared to $1,232.8 million ($1,259.2 million, net of $26.4 million of transportation costs) during 2009. This increase was due to higher commodity prices, most
significantly oil, partially offset by lower production.

|Analysis of Sales Revenue(1)($ millions) |  |   | Crude Oil |   |   | NGLs |   |   | Natural Gas |   |   | Total   |   | 
|---------------------------------------- |  | - | --------- | - | - | ---- | - | - | ----------- | - | - | ------- | - | 
|                                        
|2009 Sales Revenue                       |  | $ | 704.8     |   | $ | 63.0 |   | $ | 465.0       |   | $ | 1,232.8 |   | 
|Price variance(1)                        |  |   | 134.6     |   |   | 14.1 |   |   | 14.8        |   |   | 163.5   |   | 
|Volume variance                          |  |   | (39.5     | ) |   | (4.1 | ) |   | (52.5       | ) |   | (96.1   | ) | 
|                                        
|2010 Sales Revenue                       |  | $ | 799.9     |   | $ | 73.0 |   | $ | 427.3       |   | $ | 1,300.2 |   | 
|                                        

Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Total royalties paid during 2010 increased to $223.5 million
from $207.5 million in 2009, primarily due to higher commodity prices partially offset by lower production volumes. As a percentage of oil and gas sales, net of transportation costs, royalties
in both 2010 and 2009 were approximately 17%. We expect this percentage to increase to approximately 20% during 2011 due to the increased oil weighting within our portfolio combined with additional
production in the U.S. Royalty rates in the U.S., including state production taxes, have typically averaged 24% of sales compared to recent Canadian rates of approximately 16%.

Operating Expenses

Operating expenses during 2010 were $289.5 million or $9.54/BOE compared to $327.2 million or $9.79/BOE during 2009. Operating costs were lower
compared to 2009 due to the impact of our divestment program, as we disposed of higher operating cost properties, along with lower repairs and maintenance spending. Operating costs were lower than our
guidance of $10.20/BOE primarily due to non-cash gains on our power contracts and unanticipated equalization credits recorded during the fourth quarter.

For
2011 we expect to see a further reduction in operating costs to approximately $9.20/BOE due to the full year impact of our higher operating cost divestments combined with additional production
from our Fort Berthold and Marcellus plays where operating costs are significantly lower than our corporate average.

ENERPLUS2010 FINANCIAL
SUMMARY9

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General and Administrative Expenses ("G&A")

G&A expenses including corporate conversion costs were $2.60/BOE or $78.9 million during 2010, between our 2010 guidance of $2.55/BOE and $2.64/BOE
experienced in 2009. G&A expenses in 2010 were $9.4 million less than 2009 however, they were comparable on a BOE basis due to lower production in 2010. Our 2010 G&A expenses increased in the
fourth quarter primarily due to an 16% increase in our unit price during this time which increased our long-term compensation expense. During 2010 we also incurred $3.3 million of
corporate conversion costs to simplify our corporate structure and facilitate the conversion from a trust to a corporation. One-time costs of $11.1 million recorded in 2009 were
associated with staff reductions and transaction costs related to the issuance of our senior notes.

G&A
expenses included non-cash G&A charges of $5.9 million or $0.20/BOE compared to $6.5 million or $0.20/BOE for 2009. These amounts relate solely to our trust unit rights
incentive plan and are determined using a binomial lattice option-pricing model. See Note 11 for further details.

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

|General and Administrative Costs($ millions)  |  |   | 2010 |  |  |   | 2009 | 
|--------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                              |  |  
|Cash                                          |  | $ | 69.7 |  |  | $ | 70.7 | 
|Corporate conversion and other one-time items |  |   | 3.3  |  |  |   | 11.1 | 
|Trust unit rights incentive plan (non-cash)   |  |   | 5.9  |  |  |   | 6.5  | 
|                                              |  |  
|Total G&A                                     |  | $ | 78.9 |  |  | $ | 88.3 | 
|                                              |  |  

|
|

|(Per BOE)                                     |  |   | 2010 |  |  |   | 2009 | 
|--------------------------------------------- |  | - | ---- |  |  | - | ---- | 
|                                              |  |  
|Cash                                          |  | $ | 2.29 |  |  | $ | 2.11 | 
|Corporate conversion and other one-time items |  |   | 0.11 |  |  |   | 0.33 | 
|Trust unit rights incentive plan (non-cash)   |  |   | 0.20 |  |  |   | 0.20 | 
|                                              |  |  
|Total G&A                                     |  | $ | 2.60 |  |  | $ | 2.64 | 
|                                              |  |  

We have been actively working to improve not only our underlying asset base, but also our internal technical capabilities. Throughout 2010 we increased our
staffing levels within our U.S. operations by 50% in order to effectively manage our growing portfolio in the Bakken and the Marcellus plays and have continued to enhance our technical
capabilities within our Canadian operations. These changes will result in an increase in our G&A expense during 2011.

The
adoption of International Financial Reporting Standards ("IFRS") will also impact our G&A expenses going forward. Previously staff costs associated with our acquisition and divestment activities
were capitalized, however under IFRS these costs will now be expensed and are expected to increase our 2011 G&A expenses by $0.20/BOE.

As
a result of these changes and lower annual average production volumes in 2011 we expect G&A costs will average approximately $3.30/BOE. As our capital plans are executed and production volumes
increase throughout 2011 and into 2012, we expect to see a reduction in G&A expenses per 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 9 for further
details.

Interest
on long-term debt during 2010 totaled $47.0 million, a $16.4 million increase from $30.6 million in 2009. This increase is due to higher average indebtedness
year over year, the full year impact of higher interest rates associated with our senior unsecured notes issued in June 2009 and increased fees on our credit facility in 2010 after the renewal
on June 30. Interest expense for 2010 also included a $5.0 million extension fee in conjunction with our credit facility renewal. Our weighted average interest rate was 4.9% in 2010
compared to 4.2% in 2009.

10      ENERPLUS2010 FINANCIAL
SUMMARY

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For the year ended December 31, 2010 non-cash interest gains were $0.3 million compared to non-cash losses of $25.7 million in 2009. The changes in the
fair value of our interest rate swaps and the interest component on our CCIRS cause non-cash interest to fluctuate between periods.

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

|Interest Expense($ millions)  |  |   | 2010 |   |  |  |   | 2009 | 
|----------------------------- |  | - | ---- | - |  |  | - | ---- | 
|                              |  |  
|Interest on long-term debt    |  | $ | 47.0 |   |  |  | $ | 30.6 | 
|Non-cash interest loss/(gain) |  |   | (0.3 | ) |  |  |   | 25.7 | 
|                              |  |  
|Total Interest Expense        |  | $ | 46.7 |   |  |  | $ | 56.3 | 
|                              |  |  

Approximately 59% of our debt was based on fixed interest rates while 41% had floating interest rates at December 31, 2010. In comparison, at
December 31, 2009 approximately 77% of our debt was based on fixed interest rates and 23% was floating.

Foreign Exchange

During the year we realized foreign exchange losses of $28.0 million compared to gains of $18.5 million in 2009. Enerplus' foreign exchange gains
and losses typically originate from our U.S. dollar denominated transactions with our U.S. subsidiary. The U.S. dollar depreciated against the Canadian dollar during 2009 and
continued to lose ground in 2010. During 2009 our Canadian operating entity had net U.S. dollar payables which resulted in realized foreign exchange gains. However, during 2010 we had net
U.S. dollar receivables and the continued weakening of the U.S. dollar resulted in realized foreign exchange losses. In addition, on June 19, 2010 we made our first principle
repayment on our US$175 million senior notes. As a result of the underlying CCIRS on these notes, which fixed the principal repayment at a foreign exchange rate of 0.6522 US$/CDN$, we
realized a foreign exchange loss of $18.0 million and a corresponding non-cash gain of $18.0 million.

Unrealized
foreign exchange gains in 2010 totaled $28.9 million compared to $41.1 million in 2009. Unrealized foreign exchange gains and losses occur on the translation of our
U.S. dollar denominated debt as well as on the mark to market of our CCIRS and foreign exchange swaps. See Note 10 for further details.

|Foreign Exchange($ millions)            |  |   | 2010  |   |  |  |   | 2009  |   | 
|--------------------------------------- |  | - | ----- | - |  |  | - | ----- | - | 
|                                        |  |  
|Realized foreign exchange loss/(gain)   |  | $ | 28.0  |   |  |  | $ | (18.5 | ) | 
|Unrealized foreign exchange loss/(gain) |  |   | (28.9 | ) |  |  |   | (41.1 | ) | 
|                                        |  |  
|Total Foreign Exchange loss/(gain)      |  | $ | (0.9  | ) |  |  | $ | (59.6 | ) | 
|                                        |  |  

Capital Expenditures

Development Capital Spending

During 2010 our development capital spending totaled $542.7 million, net of DRCs of $18.3 million. This represents a $243.6 million or an
81% increase from 2009 levels as we increased spending on our early stage growth assets. Our 2010 spending was $27.7 million above our guidance of $515 million, approximately
$20.0 million of which related to the Marcellus play. We incurred additional completion costs as we increased the lateral length along with the number of frac stages in several wells. We also
experienced some cost inflation in the Marcellus due to the high levels of activity in the area and demand for services. In Canada, we accelerated our capital spending at Tommy Lakes by approximately
$4.0 million along with lower than expected DRCs of approximately $8.0 million. These increases were somewhat offset by completion delays on wells in Fort Berthold.

Property Acquisitions and Dispositions

In support of our strategy to reposition our portfolio and improve our focus and profitability we successfully completed $1.0 billion of acquisitions and
$871.5 million of dispositions during 2010. When we initiated this strategy in 2009, we acquired new properties totaling $272.0 million and disposed of $104.3 million of assets.
Our acquisitions in 2010 related primarily to undeveloped land in both Canada and the U.S. that are expected to add production and reserves in the years ahead. In 2010, we acquired
58,921 net acres in the Fort Berthold play for US$588.0 million which also included production of 1,900 BOE/day. In addition we added 75,317 net acres (70,833 operated) to
our existing

ENERPLUS2010 FINANCIAL
SUMMARY11

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land
position in the Marcellus play for $169.3 million and fulfilled $92.3 million in carry obligation. In Canada, we purchased 104,500 net acres of prospective land contiguous to
our existing holdings in the Freda Lake, Neptune and Oungre areas of the Saskatchewan Bakken for $118.7 million. We also acquired 36,100 net acres of undeveloped land in the British
Columbia and Alberta Deep Basin for $25.9 million. Our 2010 acquisitions are listed below:

|Play Type                |  |   | Amount CDN(millions)(1) |  | Net Acreage |  |  | Production(BOE/day) | 
|------------------------ |  | - | ----------------------- |  | ----------- |  |  | ------------------- | 
|                         |  |  
|U.S. Acquisitions        |  |   |                         |  |             |  |  |                     | 
|Fort Berthold            |  | $ | 588.0                   |  | 58,921      |  |  | 1,900               | 
|Marcellus                |  |   | 169.3                   |  | 75,317      |  |  |                    | 
|Marcellus carry spending |  |   | 92.3                    |  |            |  |  |                    | 
|Other                    |  |   | 10.5                    |  | 3,750       |  |  |                    | 
|                         |  |  
|Total U.S.               |  | $ | 860.1                   |  | 137,988     |  |  | 1,900               | 
|Canadian Acquisitions    |  |   |                         |  |             |  |  |                     | 
|Bakken                   |  | $ | 118.7                   |  | 104,500     |  |  |                    | 
|Deep Basin Gas           |  |   | 25.9                    |  | 36,100      |  |  |                    | 
|Other                    |  |   | 13.4                    |  | 3,400       |  |  |                    | 
|                         |  |  
|Total Canadian           |  | $ | 158.0                   |  | 144,000     |  |  |                    | 
|                         |  |  
|Total Acquisitions       |  | $ | 1,018.1                 |  | 281,988     |  |  | 1,900               | 
|                         |  |  

Our dispositions in 2010 included $465.2 million in proceeds from three non-core property packages representing approximately
10,400 BOE/day of production and $404.8 million in proceeds from the sale of our 100% working interest in the Kirby oil sands lease.

In
2009 we acquired Bakken land interests in North Dakota and Southeast Saskatchewan as well as a 21.5% non-operated working interest in the Marcellus shale gas play. Total consideration
for the Marcellus acquisition was US$411 million, comprised of US$164.4 million in cash that was paid upon closing and US$246.6 million to be paid over time as 50% of the
operator's future drilling and completion costs. At December 31, 2010 our remaining Marcellus carry commitment was US$147.0 million compared to US$237.3 million at
December 31, 2009.

Our
2009 divestments related mainly to the sale of a non-core oil property in Western Canada for proceeds of $101.0 million.

Total
net capital expenditures for 2010 and 2009 are outlined below:

|Capital Expenditures($ millions) |  |   | 2010    |   |  |  |   | 2009   |   | 
|-------------------------------- |  | - | ------- | - |  |  | - | ------ | - | 
|                                 |  |  
|Development expenditures(1)(2)   |  | $ | 457.4   |   |  |  | $ | 231.8  |   | 
|Plant and facilities             |  |   | 85.3    |   |  |  |   | 67.3   |   | 
|                                 |  |  
|Development Capital              |  |   | 542.7   |   |  |  |   | 299.1  |   | 
|Office                           |  |   | 4.0     |   |  |  |   | 6.7    |   | 
|                                 |  |  
|Sub-total                        |  |   | 546.7   |   |  |  |   | 305.8  |   | 
|Property acquisitions(2)(3)      |  |   | 1,018.1 |   |  |  |   | 272.0  |   | 
|Property dispositions(3)         |  |   | (871.5  | ) |  |  |   | (104.3 | ) | 
|                                 |  |  
|Total Net Capital Expenditures   |  | $ | 693.3   |   |  |  | $ | 473.5  |   | 
|                                 |  |  

We expect development capital spending in 2011 will be approximately $650 million with 65% projected to be invested in oil projects. We expect to focus
approximately 85% of our spending on our Bakken, Waterflood and Marcellus resource plays. With continued low natural gas prices the majority of our natural gas spending will be directed to our
non-operated Marcellus interest to further delineate the resource and preserve our lease positions.

12      ENERPLUS2010 FINANCIAL
SUMMARY

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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 2010
DDA&A was $645.3 million or $21.27/BOE compared to $650.4 million or $19.45/BOE in 2009. The increase in our 2010 DDA&A is attributable to a higher depletion rate due to negative reserve
revisions experienced at December 31, 2009.

No
impairment of the Fund's PP&E values existed at December 31, 2010 using year-end reserves and management's estimates of future prices. Our future price estimates are more fully
discussed in Note 5.

Goodwill

The goodwill balance of $599.7 million is a result of previous corporate acquisitions and represents the excess of the total purchase price over the fair
value of the net identifiable assets and liabilities acquired. The goodwill balance with respect to our U.S operations is exposed to foreign currency fluctuations as it is translated into Canadian
dollars at the period end exchange rate. No goodwill impairment existed as of December 31, 2010.

Asset Retirement Obligations

In connection with our operations, we will incur abandonment and reclamation costs for our assets including surface leases, wells, facilities and pipelines.
Total future asset retirement obligations included on our balance sheet are estimated by management based on our net ownership interest, estimated costs to abandon and reclaim and the estimated timing
of the costs to be incurred in future periods.

We
have estimated the net present value of our asset retirement obligations to be $208.7 million at December 31, 2010 compared to $230.5 million at December 31, 2009, based
on total undiscounted liabilities of $590.2 million and $676.8 million respectively. The majority of the decrease in 2010 related to asset retirement obligations associated with our
non-core divestments. See Note 7 for further information.

We
take an active approach to managing our abandonment, reclamation and remediation obligations. During 2010 we spent $17.2 million
(2009  $13.8 million) on our asset retirement obligations and we expect to spend approximately $19.0 million in 2011. Our abandonment and
reclamation costs are expected to be incurred over the next 66 years with the majority between 2031 and 2050. We do not reserve cash or assets for the purpose of funding our future asset
retirement obligations. Any reclamation or abandonment costs incurred will generally be funded out of cash flow. If we are unable to remedy an environmental claim we may be required to suspend
operations or enter into interim compliance measures pending satisfactory resolution of the matter.

There
are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our
estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserve estimates, costs and technology.

Environment

Our operations are subject to laws and regulations concerning pollution, protection of the environment and the handling of hazardous materials and waste. These
laws require us to remedy the effect of our activities on the environment at our operating sites including
dismantling production facilities and remediating any damage caused by the release of substances. We are seeing an increase in the number of regulations related to environmental compliance along with
stricter thresholds within the regulations. Compliance with this legislation may require significant expenditures.

Specific
greenhouse gas ("GHG") regulations have been enacted in Alberta and British Columbia and the cost of our compliance in 2010 was approximately $0.9 million. Federal GHG regulations have
not been finalized however we do not expect a material impact on our business given our current operations. We would also anticipate a transition period once the regulations are finalized to provide
companies the opportunity to modify their operations and practices. In the United States, the federal Environmental Protection Agency has issued a GHG reporting and tailoring rule and we do not
expect the rule to have a material impact on our operations. The uncertainty surrounding the direction from various levels of government affects our ability to manage potential risks and opportunities
associated with GHG emissions from our operations.

We
may be subject to remedial environmental and litigation costs resulting from unknown and unforeseeable environmental impacts arising from our operations. There are inherent risks of oil spills and
pipeline leaks at our operating sites and clean-up costs may be significant. We have

ENERPLUS2010 FINANCIAL
SUMMARY13

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active
site inspection and corrosion risk management programs along with asset integrity management designed to ensure compliance with regulations and reduce the number of incidences. We also carry
pollution insurance to help mitigate the cost of spills should they occur.

Taxes

Future Income Taxes

Future income taxes arise from differences between the accounting and tax basis of assets and liabilities. The balance will be realized over time as future
income tax assets and liabilities are realized or settled.

The
future income tax recovery for 2010 was $54.8 million compared to $93.2 million in 2009. The decrease in the future income tax recovery was a result of higher net income in our
operating entities during 2010 compared to 2009.

Current Income Taxes

Under the income trust structure, in effect prior to January 1, 2011, payments were made between our operating entities and the Fund, which ultimately
transferred both income and future income tax liability to our unitholders. As a result minimal cash income taxes were generally paid by our Canadian operating entities. Effective January 1,
2011 we are subject to normal Canadian corporate taxes as a result of our conversion. However, we do not expect to pay cash taxes in Canada prior to 2013 as we have $2.0 billion of tax pools to
offset taxable income. This estimate may vary depending on numerous factors, including fluctuations in commodity prices and acquisition and disposition activity.

We
are subject to normal course income tax audits by various taxation authorities. During the fourth quarter of 2010 we recorded a $16.6 million provision and corresponding charge to current
income tax expense with respect to an ongoing income tax audit of a predecessor company from a prior corporate acquisition. At this time we are uncertain of the timing and final outcome of this
matter.

During
2010 our U.S. operations recorded a current income tax recovery in the amount of $46.9 million compared to a current income tax expense of $0.2 million in 2009. The 2010
recovery is due to higher capital spending levels in 2010 which has resulted in a tax loss that we plan to carry back to recover prior period cash income taxes. We expect to pay a nominal amount of
U.S. cash taxes in 2011.

Tax Pools

We estimate our tax pools at December 31, 2010 to be as follows:

|Pool Type($ millions) |                      |   | Total |    
|--------------------- | -------------------- | - | ----- | ---
|                     
|                      | COGPE                |   | $     | 475
|                      | CDE                  |   |       | 178
|                      | UCC                  |   |       | 498
|                      | CEE                  |   |       | 151
|                      | Tax losses and other |   |       | 669
|                     
|Canadian tax pools    |                      | $ | 1,971 |    
|US tax pools          |                      |   | 1,167 |    
|                     
|Total                 |                      | $ | 3,138 |    
|                     

Net Income

Net income in 2010 was $127.1 million or $0.72 per trust unit compared to $89.1 million or $0.53 per trust unit in 2009. The increase was
primarily due to a $67.4 million increase in oil and gas sales, net of transportation, and a $37.7 million decrease in operating costs, partially offset by decreased foreign exchange
gains of $58.6 million.

Cash Flow from Operating Activities

Cash flow from operating activities in 2010 was $703.1 million or $3.96 per trust unit compared to $775.8 million or $4.58 per trust unit in 2009.
The decrease was primarily due to lower cash gains on our commodity derivative instruments, higher realized foreign exchange losses and increased working capital. This was partially offset by higher
oil and gas sales and lower operating expenses.

14      ENERPLUS2010 FINANCIAL
SUMMARY

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Selected Financial Results

|                                                    |  | Year ended
December 31, 2010 |                        | Year ended
December 31, 2009
|--------------------------------------------------- |  | ---------------------------- | ---------------------- | ----------------------------
|Per BOE of production (6:1)                         |  |                              | Operating
Cash
Flow(1) |                             
|                                                    |  |                             
|Production per day                                  |  |                              |                        |                             
|                                                    |  |                             
|Weighted average sales price(2)                     |  | $                            | 42.85                  |                             
|Royalties                                           |  |                              | (7.37                  | )                           
|Commodity derivative instruments                    |  |                              | 1.64                   |                             
|Operating costs                                     |  |                              | (9.61                  | )                           
|General and administrative expenses                 |  |                              | (2.40                  | )                           
|Interest, foreign exchange and other expenses       |  |                              | (1.85                  | )                           
|Current income tax                                  |  |                              | 1.00                   |                             
|Restoration and abandonment cash costs              |  |                              | (0.57                  | )                           
|Depletion, depreciation, amortization and accretion |  |                              |                       |                             
|Future income tax (expense)/recovery                |  |                              |                       |                             
|                                                    |  |                             
|Total per BOE                                       |  | $                            | 23.69                  |                             
|                                                    |  |                             

ENERPLUS2010 FINANCIAL
SUMMARY15

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SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS

The following table provides a geographical analysis of key operating and financial results for 2010 and 2009.

|                                         |                                                     | Year ended December 31, 2010 |        | Year ended December 31, 2009
|---------------------------------------- | --------------------------------------------------- | ---------------------------- | ------ | ----------------------------
|(CDN$ millions, except per unit amounts) |                                                     |                              | Canada |                             
|                                         |                                                     |                             
|Average Daily Production Volumes         |                                                     |                              |        |                             
|                                         | Natural gas (Mcf/day)                               |                              |        | 266,671                     
|                                         | Crude oil (bbls/day)                                |                              |        | 21,712                      
|                                         | Natural gas liquids (bbls/day)                      |                              |        | 3,889                       
|                                         | Total daily sales (BOE/day)                         |                              |        | 70,046                      
|Pricing(1)                               |                                                     |                              |        |                             
|                                         | Natural gas (per Mcf)                               |                              | $      | 3.94                        
|                                         | Crude oil (per bbl)                                 |                              | $      | 70.05                       
|                                         | Natural gas liquids (per bbl)                       |                              | $      | 51.41                       
|Capital Expenditures                     |                                                     |                              |        |                             
|                                         | Development capital and office                      |                              | $      | 307.2                       
|                                         | Acquisitions of oil and gas properties              |                              | $      | 158.0                       
|                                         | Dispositions of oil and gas properties              |                              | $      | (871.5                      
|Revenues                                 |                                                     |                              |        |                             
|                                         | Oil and gas sales(1)                                |                              | $      | 1,011.9                     
|                                         | Royalties(2)                                        |                              | $      | (154.7                      
|                                         | Commodity derivative instruments gain/(loss)        |                              | $      | 24.0                        
|Expenses                                 |                                                     |                              |        |                             
|                                         | Operating                                           |                              | $      | 271.3                       
|                                         | General and administrative                          |                              | $      | 67.5                        
|                                         | Depletion, depreciation, amortization and accretion |                              | $      | 544.8                       
|                                         | Current income taxes (recovery)/expense             |                              | $      | 16.6                        
|                                         |                                                     |                             

16      ENERPLUS2010 FINANCIAL
SUMMARY

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THREE YEAR SUMMARY OF KEY MEASURES

Crude oil and natural gas sales increased for the first half of 2008 due to increased commodity prices and increased production from the Focus acquisition which
we completed in February 2008. Oil and natural gas sales decreased in the latter part of 2008 with the sharp decline in commodity prices and were flat during 2009 and 2010 as rising crude oil
prices have largely been offset by declining natural gas prices and production levels as a result of disposition activity.

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

|($ millions, except per unit amounts) |  |   | 2010    |  |  |   | 2009    |  |   | 2008    | 
|------------------------------------- |  | - | ------- |  |  | - | ------- |  | - | ------- | 
|                                      |  |  
|Oil and gas sales(1)                  |  | $ | 1,300.2 |  |  | $ | 1,232.8 |  | $ | 2,304.2 | 
|Net income                            |  |   | 127.1   |  |  |   | 89.1    |  |   | 888.9   | 
|Per unit (Basic)(2)                   |  |   | 0.72    |  |  |   | 0.53    |  |   | 5.54    | 
|Per unit (Diluted)(2)                 |  |   | 0.71    |  |  |   | 0.53    |  |   | 5.53    | 
|Cash flow from operating activities   |  |   | 703.1   |  |  |   | 775.8   |  |   | 1,262.8 | 
|Per unit (Basic)(2)                   |  |   | 3.96    |  |  |   | 4.58    |  |   | 7.86    | 
|Cash distributions to unitholders(3)  |  |   | 384.1   |  |  |   | 368.2   |  |   | 786.1   | 
|Per unit (Basic)(2)(3)                |  |   | 2.16    |  |  |   | 2.17    |  |   | 4.89    | 
|Payout ratio(4)                       |  |   | 55%     |  |  |   | 47%     |  |   | 62%     | 
|Adjusted payout ratio(4)              |  |   | 132%    |  |  |   | 87%     |  |   | 109%    | 
|Total assets                          |  |   | 5,835.2 |  |  |   | 5,905.5 |  |   | 6,230.1 | 
|Long-term debt, net of cash(5)        |  |   | 724.0   |  |  |   | 485.3   |  |   | 657.4   | 
|                                      |  |  

LIQUIDITY AND CAPITAL RESOURCES

Debt

During the second quarter we extended our unsecured, covenant-based bank credit facility for a three year term, maturing June 30, 2013. Based on our
forecasted cash requirements, our anticipated ongoing access to debt and equity markets, combined with the significant increase in standby credit charges, we chose to reduce our facility size from
$1.4 billion to $1.0 billion. Drawn fees under the facility range between 200 and 375 basis points over bankers' acceptance rates whereas previously they ranged from 55 to
110 basis points. We are currently paying 200 basis points over bankers' acceptance rates which have been trading around 1%. Standby fees on the undrawn portion of the facility are based
on 25% of the drawn pricing. We have the ability to request an extension of the facility each year or repay the entire balance at the end of the term. A fee of $5.0 million was paid to extend
the facility for three years and was recorded in interest expense during the second quarter. The amending agreement was filed on July 21, 2010 as a "Material Document" on the Fund's' SEDAR
profile at www.sedar.com.

On
June 19, 2010 we settled our first principal payment on the US$175 million senior notes and associated cross currency interest rate swap principal settlement for a total of
$53.7 million. See "Commitments" and Notes 8 and 13 for more information.

Total
debt at December 31, 2010 was $732.4 million, an increase of $173.5 million from $558.9 million at December 31, 2009, which includes the current portion of our
senior notes. Long-term debt at December 31, 2010 was comprised of $234.7 million of bank indebtedness and $497.7 million of senior notes. The increase of
$173.5 million in 2010 is mainly the result of our increased development capital spending throughout the year.

Our
working capital at December 31, 2010, excluding cash, current deferred financial assets and credits, current portion of long-term debt and future income taxes decreased by
$64.9 million compared to December 31, 2009. This change was due to increased payables related to our

ENERPLUS2010 FINANCIAL
SUMMARY17

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development
capital spending during the fourth quarter, along with decreased receivables due to lower production in December 2010. We expect to finance our negative working capital with our
cash flow or bank indebtedness.

We
have continued to maintain a conservative balance sheet as demonstrated below:

|Financial Leverage and Coverage                      |  | Year ended
Dec. 31, 2010 |  |  | Year ended
Dec. 31, 2009 | 
|---------------------------------------------------- |  | ------------------------ |  |  | ------------------------ | 
|                                                     |  |                         
|Long-term debt to cash flow (12 month trailing)(1)   |  | 1.0 x                    |  |  | 0.6 x                    | 
|Cash flow to interest expense (12 month trailing)(2) |  | 15.0 x                   |  |  | 25.4 x                   | 
|Long-term debt to long-term debt plus equity(1)      |  | 16%                      |  |  | 10%                      | 
|                                                     |  |                         

Payments with respect to the bank facilities, senior notes and other third party debt have priority over claims of and future dividends to our shareholders. At
December 31, 2010, we were in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing cash flow.

We
expect to have adequate liquidity from cash flow and our bank credit facility to fund planned development capital spending and working capital requirements for 2011. Our capital spending and
dividends are expected to exceed our cash flow in 2011 and 2012, however our balance sheet provides us the flexibility to support these plans. We expect that our debt-to-cash
flow ratio will increase during this time as we continue to invest in earlier stage growth assets where there is a longer lead time to production and cash flow. We will be actively monitoring our debt
levels and may consider selling non-cash generating assets or selling part of our non-operated Marcellus interests to manage our debt and maintain our financial flexibility.
Our debt-to-cash flow levels are anticipated to decrease after 2012 as production and cash flow from our growth plays accelerates.

Counterparty Credit

Oil and Gas Sales Counterparties

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

Financial Derivative Counterparties

We are exposed to credit risk in the event of non-performance by our financial counterparties regarding our derivative contracts. We mitigate this
risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association ("ISDA")
agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other under all
outstanding transactions and settle with a single net amount in the case of a credit event. To date we have not experienced any losses due to non-performance by our derivative
counterparties. At December 31, 2010 we had $13.0 million in mark-to-market assets offset by $103.6 million of mark-to-market
liabilities resulting in a net liability position of $90.6 million.

Cash Flow from Operating Activities, Cash Distributions and Payout Ratio

Cash flow from operating activities ("cash flow") and cash distributions are reported on the Consolidated Statements of Cash Flows. During 2010 cash
distributions of $384.1 million were funded entirely through cash flow of $703.1 million.

Our
payout ratio, which is calculated as cash distributions divided by cash flow, was 55% for 2010 compared to 47% in 2009. Our adjusted payout ratio, which is calculated as cash distributions plus
development capital and office expenditures divided by cash flow, was 132% for

18      ENERPLUS2010 FINANCIAL
SUMMARY

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2010
compared to 87% in 2009. Our adjusted payout ratio increased during 2010 mainly due to higher capital spending levels which included spending on earlier stage growth assets that did not generate
immediate production or cash flow. See "Non-GAAP Measures" above.

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

|($ millions, except per unit amounts)                    |  |   | 2010   |   |  |  |   | 2009   |   |   | 2008    | 
|-------------------------------------------------------- |  | - | ------ | - |  |  | - | ------ | - | - | ------- | 
|                                                         |  |  
|Cash flow from operating activities                      |  | $ | 703.1  |   |  |  | $ | 775.8  |   | $ | 1,262.8 | 
|Cash distributions                                       |  |   | 384.1  |   |  |  |   | 368.2  |   |   | 786.1   | 
|                                                         |  |  
|Excess of cash flow over cash distributions              |  | $ | 319.0  |   |  |  | $ | 407.6  |   | $ | 476.7   | 
|Net income                                               |  | $ | 127.1  |   |  |  | $ | 89.1   |   | $ | 888.9   | 
|(Shortfall)/excess of net income over cash distributions |  | $ | (257.0 | ) |  |  | $ | (279.1 | ) | $ | 102.8   | 
|Cash distributions per weighted average trust unit       |  | $ | 2.16   |   |  |  | $ | 2.17   |   | $ | 4.89    | 
|Payout ratio(1)                                          |  |   | 55%    |   |  |  |   | 47%    |   |   | 62%     | 
|Adjusted payout ratio(1)                                 |  |   | 132%   |   |  |  |   | 87%    |   |   | 109%    | 
|                                                         |  |  

Dividend Policy

As a corporation we pay monthly dividends whereas we previously paid monthly distributions as an income trust. We intend to continue to distribute a significant
portion of our cash flow to our shareholders and we currently pay a monthly dividend of $0.18/share. We will continue to assess dividend levels with respect to anticipated cash flows, debt levels and
service requirements, capital spending plans and capital market conditions and will adjust dividend levels as necessary. The payment of dividends, or the amount thereof, is not guaranteed.

COMMITMENTS

We have contracted to transport 200 MMcf/day of natural gas in Canada with contract terms that range anywhere from one month to five years. We have also
contracted 6,000 MMbtu/day gas gathering capacity for our Marcellus production, which increases to 13,650 MMbtu/day on June 1, 2011 until March 31, 2022. In addition we
have contracted for 4,500 MMbtu/day of transportation capacity on Columbia Gas Transmission for our Marcellus sales gas until January 2014.

We
have contracted for 1,000 bbl/day of transportation capacity for our Bakken crude oil in the U.S. beginning May 2011 for five years with an additional 5,000 bbl/day
beginning January 1, 2013 for five years.

Our
gas supply dedicated to aggregator sales contracts is expected to be approximately 7% of gas production or 21 MMcf/day. Under these arrangements, we receive a price based on the average
netback price of the pool.

We
have also entered into contracts to secure a drilling rig and related fracturing services for two years commencing in early 2011 for our U.S. Bakken play. Our minimum commitment is
approximately $4.6 million per month for these contracts.

Our
U.S. and Canadian office leases expire in 2011 and 2014 respectively. Annual costs of these lease commitments include rent and operating fees. Our commitments, contingencies and guarantees are
more fully described in Note 14.

ENERPLUS2010 FINANCIAL
SUMMARY19

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As at December 31, 2010 we have the following minimum annual commitments including long-term debt:

|                                       |  |   |         |  |  | Minimum Annual Commitment Each Year |       |  | Total
Committed |      
|-------------------------------------- |  | - | ------- |  |  | ----------------------------------- | ----- |  | --------------- | -----
|($ millions)                           |  |   | Total   |  |  |                                     | 2011  |  |                 | 2012 
|                                       |  |  
|Bank credit facility                   |  | $ | 234.7   |  |  | $                                   |      |  | $               |     
|Senior unsecured notes(1)(2)           |  |   | 573.1   |  |  |                                     | 64.6  |  |                 | 64.6 
|Pipeline commitments                   |  |   | 82.8    |  |  |                                     | 16.8  |  |                 | 12.6 
|Processing commitments                 |  |   | 20.3    |  |  |                                     | 3.5   |  |                 | 3.6  
|Marcellus carry commitment(4)          |  |   | 146.2   |  |  |                                     | 116.0 |  |                 | 30.2 
|Drilling and completions commitment(5) |  |   | 110.6   |  |  |                                     | 42.7  |  |                 | 55.3 
|Asset retirement obligations(6)        |  |   | 590.2   |  |  |                                     | 19.0  |  |                 | 20.0 
|Office lease                           |  |   | 44.6    |  |  |                                     | 11.3  |  |                 | 11.4 
|                                       |  |  
|Total commitments(3)                   |  | $ | 1,802.5 |  |  | $                                   | 273.9 |  | $               | 197.7
|                                       |  |  

ACCUMULATED DEFICIT

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

TRUST UNIT INFORMATION

We had 178,648,000 trust units outstanding at December 31, 2010 compared to 177,061,000 trust units outstanding at December 31,
2009. At December 31, 2010 this included 4,007,000 exchangeable limited partnership units which were convertible at the option of the holder into 0.425 of an Enerplus trust unit
(1,703,000 trust units). During 2010, a total of 2,375,000 partnership units were converted into 1,009,000 trust units.

During
2010, 1,587,000 trust units (2009  1,065,000) 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 $35.4 million (2009  $24.2 million) of additional equity
for the Company. See Note 11 for further details.

The
weighted average basic number of trust units outstanding during 2010 was 177,737,000 compared to 169,280,000 trust units during 2009.

As
a result of our conversion from an income trust into a corporation, all of our outstanding trust units were converted to common shares at a ratio of 1:1 and all outstanding exchangeable partnership
units were converted to common shares on the basis of 0.425 of a common share for each partnership unit. At February 22, 2011 we had 178,939,000 common shares outstanding.

20      ENERPLUS2010 FINANCIAL
SUMMARY

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QUARTERLY FINANCIAL INFORMATION

Oil and natural gas sales were essentially flat during 2009 and 2010 as rising crude oil prices have largely been offset by declining natural gas prices. Our
reduced production levels during the last two years have also put downward pressure on oil and gas sales.

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

|                                               |  |   | Oil and      |  |   | Net           |   | Net Income/(Loss) Per Trust Unit
|---------------------------------------------- |  | - | ------------ |  | - | ------------- | - | --------------------------------
|(CDN$ millions, except per trust unit amounts) |  |   | Gas Sales(1) |  |   | Income/(Loss) |   |                                 
|                                              
|2010                                           |  |   |              |  |   |               |   |                                 
|Fourth Quarter                                 |  | $ | 313.2        |  | $ | (1.0          | ) | $                               
|Third Quarter                                  |  |   | 305.5        |  |   | 16.8          |   |                                 
|Second Quarter                                 |  |   | 318.2        |  |   | 31.3          |   |                                 
|First Quarter                                  |  |   | 363.3        |  |   | 80.0          |   |                                 
|                                               |  |   |              |  |   |               |   |                                 
|Total                                          |  | $ | 1,300.2      |  | $ | 127.1         |   | $                               
|                                              
|2009                                           |  |   |              |  |   |               |   |                                 
|Fourth Quarter                                 |  | $ | 333.3        |  | $ | 2.7           |   | $                               
|Third Quarter                                  |  |   | 292.1        |  |   | 38.2          |   |                                 
|Second Quarter                                 |  |   | 306.2        |  |   | (3.6          | ) |                                 
|First Quarter                                  |  |   | 301.2        |  |   | 51.8          |   |                                 
|                                               |  |   |              |  |   |               |   |                                 
|Total                                          |  | $ | 1,232.8      |  | $ | 89.1          |   | $                               
|                                              

SUMMARY FOURTH QUARTER INFORMATION

In comparing the fourth quarter of 2010 with the same period in 2009:

ENERPLUS2010 FINANCIAL
SUMMARY21

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The
following tables provide an analysis of key financial and operating results for the three months ended December 31, 2010 and 2009.

|(CDN$ millions, except per unit amounts)                                       |  |   | Three Months Ended
December 31, 2010 |   |  |  |   | Three Months Ended
December 31, 2009 |   | 
|------------------------------------------------------------------------------ |  | - | ------------------------------------ | - |  |  | - | ------------------------------------ | - | 
|                                                                               |  |  
|Financial                                                                      |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income/(loss)                                                              |  | $ | (1.0                                 | ) |  |  | $ | 2.7                                  |   | 
|Cash Flow from Operating Activities                                            |  | $ | 146.8                                |   |  |  | $ | 188.6                                |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 96.4                                 |   |  |  | $ | 95.5                                 |   | 
|Financial per Unit(2)                                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Net Income/(loss)                                                              |  | $ | (0.01                                | ) |  |  | $ | 0.02                                 |   | 
|Cash Flow from Operating Activities                                            |  | $ | 0.82                                 |   |  |  | $ | 1.07                                 |   | 
|Cash Distributions to Unitholders(1)                                           |  | $ | 0.54                                 |   |  |  | $ | 0.54                                 |   | 
|Payout Ratio(3)                                                                |  |   | 66%                                  |   |  |  |   | 51%                                  |   | 
|Adjusted Payout Ratio(3)                                                       |  |   | 223%                                 |   |  |  |   | 114%                                 |   | 
|Average Daily Production                                                       |  |   | 80,114                               |   |  |  |   | 86,777                               |   | 
|Selected Financial Results per BOE(4)                                          |  |   |                                      |   |  |  |   |                                      |   | 
|Oil and Gas Sales(5)                                                           |  | $ | 42.49                                |   |  |  | $ | 41.75                                |   | 
|Royalties                                                                      |  |   | (6.21                                | ) |  |  |   | (6.56                                | ) | 
|Commodity Derivative Instruments gains                                         |  |   | 1.02                                 |   |  |  |   | 3.34                                 |   | 
|Operating Costs                                                                |  |   | (8.29                                | ) |  |  |   | (9.27                                | ) | 
|General and Administrative expenses                                            |  |   | (2.97                                | ) |  |  |   | (3.30                                | ) | 
|Interest and Foreign Exchange expenses                                         |  |   | (2.95                                | ) |  |  |   | (0.72                                | ) | 
|Taxes                                                                          |  |   | (0.40                                | ) |  |  |   | 0.66                                 |   | 
|Restoration and Abandonment costs                                              |  |   | (0.96                                | ) |  |  |   | (0.64                                | ) | 
|                                                                               |  |  
|Cash Flow from Operating Activities before changes in non-cash working capital |  | $ | 21.73                                |   |  |  | $ | 25.26                                |   | 
|                                                                               |  |  
|Weighted Average Number of Units Outstanding (thousands)                       |  |   | 178,368                              |   |  |  |   | 176,872                              |   | 
|Development Capital Expenditures                                               |  | $ | 229.0                                |   |  |  | $ | 118.9                                |   | 
|Average Benchmark Pricing                                                      |  |   |                                      |   |  |  |   |                                      |   | 
|AECO natural gas  monthly index (CDN$/Mcf)                                    |  | $ | 3.58                                 |   |  |  | $ | 4.24                                 |   | 
|AECO natural gas  daily index (CDN$/Mcf)                                      |  | $ | 3.62                                 |   |  |  | $ | 4.50                                 |   | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                                |  | $ | 3.81                                 |   |  |  | $ | 4.27                                 |   | 
|NYMEX natural gas  monthly NX3 index: CDN$ equivalent (CDN$/Mcf)              |  | $ | 3.85                                 |   |  |  | $ | 4.49                                 |   | 
|WTI crude oil (US$/bbl)                                                        |  | $ | 85.17                                |   |  |  | $ | 76.19                                |   | 
|WTI crude oil: CDN$ equivalent (CDN$/bbl)                                      |  | $ | 86.03                                |   |  |  | $ | 80.20                                |   | 
|USD$/CDN$ exchange rate                                                        |  |   | 0.99                                 |   |  |  |   | 0.95                                 |   | 
|                                                                               |  |  

22      ENERPLUS2010 FINANCIAL
SUMMARY

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SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS

|                                         |                                                     | Three months ended
December 31, 2010 |        | Three months ended
December 31, 2009
|---------------------------------------- | --------------------------------------------------- | ------------------------------------ | ------ | ------------------------------------
|(CDN$ millions, except per unit amounts) |                                                     |                                      | Canada |                                     
|                                         |                                                     |                                     
|Average Daily Production Volumes         |                                                     |                                      |        |                                     
|                                         | Natural gas (Mcf/day)                               |                                      |        | 244,510                             
|                                         | Crude oil (bbls/day)                                |                                      |        | 18,930                              
|                                         | Natural gas liquids (bbls/day)                      |                                      |        | 4,027                               
|                                         | Total daily sales (BOE/day)                         |                                      |        | 63,709                              
|Pricing(1)                               |                                                     |                                      |        |                                     
|                                         | Natural gas (per Mcf)                               |                                      | $      | 3.47                                
|                                         | Crude oil (per bbl)                                 |                                      | $      | 71.22                               
|                                         | Natural gas liquids (per bbl)                       |                                      | $      | 53.66                               
|Capital Expenditures                     |                                                     |                                      |        |                                     
|                                         | Development capital and office                      |                                      | $      | 132.4                               
|                                         | Acquisitions of oil and gas properties              |                                      | $      | 5.9                                 
|                                         | Dispositions of oil and gas properties              |                                      | $      | (537.9                              
|Revenues                                 |                                                     |                                      |        |                                     
|                                         | Oil and gas sales(1)                                |                                      | $      | 222.0                               
|                                         | Royalties(2)                                        |                                      | $      | (23.8                               
|                                         | Commodity derivative instruments gain/(loss)        |                                      | $      | (46.1                               
|Expenses                                 |                                                     |                                      |        |                                     
|                                         | Operating                                           |                                      | $      | 53.8                                
|                                         | General and administrative                          |                                      | $      | 21.2                                
|                                         | Depletion, depreciation, amortization and accretion |                                      | $      | 123.9                               
|                                         | Current income taxes (recovery)/expense             |                                      | $      | 16.6                                
|                                         |                                                     |                                     

CRITICAL ACCOUNTING POLICIES

The financial statements have been prepared in accordance with Canadian GAAP. A summary of significant accounting policies is presented in Note 2. A
reconciliation of differences between Canadian and United States GAAP is presented in Note 16. 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 net income or net income per share.

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.

ENERPLUS2010 FINANCIAL
SUMMARY23

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CRITICAL ACCOUNTING ESTIMATES

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

Reserves

The process of estimating reserves is critical to several accounting estimates. It requires significant judgments based on available geological, geophysical,
engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and gas
prices, operating costs and royalty burdens change. Reserve estimates impact net income through depletion, the determination of asset retirement obligations and the application of an impairment test.
Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income and the asset retirement obligation.

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and
the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and amortized over its useful life.

Business Combinations

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

Derivative Financial Instruments

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

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Consolidated Financial Statements

Section 1601 "Consolidated Financial Statements" establishes the requirements for the preparation of consolidated financial statements and was effective
January 1, 2011. This standard will not have a material impact on our consolidated financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

Financial Reporting Update

As a publicly accountable enterprise we are required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011.
The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported for the year ended December 31, 2010, including the opening balance sheet
as at January 1, 2010. Our transition to IFRS continues to progress according to plan and we anticipate meeting our 2011 financial reporting requirements.

24      ENERPLUS2010 FINANCIAL
SUMMARY

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On adoption of IFRS certain financial statement adjustments are required to be made retroactively against our opening retained earnings (accumulated deficit) as at January 1, 2010. However,
IFRS 1  "First time adoption of international financial reporting standards" provides entities adopting IFRS certain optional exemptions to the general
requirement for full retroactive application of IFRS. We expect to apply the following exemptions:

A
Canadian GAAP and IFRS reconciliation of our January 1, 2010 Balance Sheet and Equity is presented below. The adjustments and resulting IFRS amounts are unaudited and subject
to change.

ENERPLUS2010 FINANCIAL
SUMMARY25

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Reconciliation  Consolidated Opening Balance Sheet  January 1, 2010

|(CDN$ thousands)                              |  | Note |  |   | IFRS
January 1,
2010 |   |  |  |   | Cdn GAAP
December 31,
2009 |   |   | Difference |   | 
|--------------------------------------------- |  | ---- |  | - | -------------------- | - |  |  | - | -------------------------- | - | - | ---------- | - | 
|                                              |  |     
|Assets                                        |  |      |  |   |                      |   |  |  |   |                            |   |   |            |   | 
|Current Assets                                |  |      |  |   |                      |   |  |  |   |                            |   |   |            |   | 
|Cash                                          |  |      |  | $ | 73,558               |   |  |  | $ | 73,558                     |   | $ |           |   | 
|Accounts Receivables                          |  |      |  |   | 142,009              |   |  |  |   | 142,009                    |   |   |           |   | 
|Deferred financial assets                     |  |      |  |   | 20,364               |   |  |  |   | 20,364                     |   |   |           |   | 
|Future income taxes                           |  | c    |  |   |                     |   |  |  |   | 4,995                      |   |   | (4,995     | ) | 
|Other current                                 |  |      |  |   | 5,041                |   |  |  |   | 5,041                      |   |   |           |   | 
|                                              |  |     
|                                              |  |      |  |   | 240,972              |   |  |  |   | 245,967                    |   |   | (4,995     | ) | 
|                                              |  |     
|Property, plant and equipment                 |  | a, b |  |   | 4,420,339            |   |  |  |   | 5,000,523                  |   |   | (580,184   | ) | 
|Exploration and evaluation assets             |  | a, b |  |   | 580,184              |   |  |  |   |                           |   |   | 580,184    |   | 
|Goodwill                                      |  | a, b |  |   | 476,998              |   |  |  |   | 607,438                    |   |   | (130,440   | ) | 
|Deferred financial assets                     |  |      |  |   | 1,997                |   |  |  |   | 1,997                      |   |   |           |   | 
|Other assets                                  |  | g    |  |   | 88,324               |   |  |  |   | 49,591                     |   |   | 38,733     |   | 
|                                              |  |     
|                                              |  |      |  |   | 5,567,842            |   |  |  |   | 5,659,549                  |   |   | (91,707    | ) | 
|                                              |  |     
|                                              |  |      |  | $ | 5,808,814            |   |  |  | $ | 5,905,516                  |   | $ | (96,702    | ) | 
|                                              |  |     
|Liabilities                                   |  |      |  |   |                      |   |  |  |   |                            |   |   |            |   | 
|Current liabilities                           |  |      |  |   |                      |   |  |  |   |                            |   |   |            |   | 
|Accounts payable                              |  |      |  | $ | 257,519              |   |  |  | $ | 257,519                    |   | $ |           |   | 
|Distributions payable to unitholders          |  |      |  |   | 31,871               |   |  |  |   | 31,871                     |   |   |           |   | 
|Current portion of long-term debt             |  |      |  |   | 36,631               |   |  |  |   | 36,631                     |   |   |           |   | 
|Deferred financial credits                    |  |      |  |   | 37,437               |   |  |  |   | 37,437                     |   |   |           |   | 
|                                              |  |     
|                                              |  |      |  |   | 363,458              |   |  |  |   | 363,458                    |   |   |           |   | 
|                                              |  |     
|Long-term debt                                |  |      |  |   | 522,276              |   |  |  |   | 522,276                    |   |   |           |   | 
|Deferred financial credits                    |  |      |  |   | 54,788               |   |  |  |   | 54,788                     |   |   |           |   | 
|Deferred tax liability (FIT)                  |  | c    |  |   | 588,329              |   |  |  |   | 561,585                    |   |   | 26,744     |   | 
|Decommissioning liability (ARO)               |  | e    |  |   | 385,885              |   |  |  |   | 230,465                    |   |   | 155,420    |   | 
|                                              |  |     
|                                              |  |      |  |   | 1,551,278            |   |  |  |   | 1,369,114                  |   |   | 182,164    |   | 
|                                              |  |     
|Exchangeable limited partnership units        |  | f    |  |   | 55,816               |   |  |  |   |                           |   |   | 55,816     |   | 
|Trust unit rights incentive plan              |  | f    |  |   | 9,074                |   |  |  |   |                           |   |   | 9,074      |   | 
|                                              |  |     
|                                              |  |      |  |   | 64,890               |   |  |  |   |                           |   |   | 64,890     |   | 
|                                              |  |     
|Equity                                        |  |      |  |   |                      |   |  |  |   |                            |   |   |            |   | 
|Unitholders' capital                          |  |      |  |   | 5,580,558            |   |  |  |   | 5,715,614                  |   |   | (135,056   | ) | 
|Accumulated deficit                           |  |      |  |   | (1,751,370           | ) |  |  |   | (1,460,283                 | ) |   | (291,087   | ) | 
|Accumulated other comprehensive income/(loss) |  | d    |  |   |                     |   |  |  |   | (82,387                    | ) |   | 82,387     |   | 
|                                              |  |     
|                                              |  |      |  |   | 3,829,188            |   |  |  |   | 4,172,944                  |   |   | (343,756   | ) | 
|                                              |  |     
|                                              |  |      |  | $ | 5,808,814            |   |  |  | $ | 5,905,516                  |   | $ | (96,702    | ) | 
|                                              |  |     

26      ENERPLUS2010 FINANCIAL
SUMMARY

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Continuity of changes in equity

|Unaudited(CDN$ '000s)                       |  | Note |  |   | Unitholder's
Capital |   |   | Accumulated
other
comprehensive
income |   |   | Accumulated
deficit |   |   | Total
Equity |   | 
|------------------------------------------- |  | ---- |  | - | -------------------- | - | - | -------------------------------------- | - | - | ------------------- | - | - | ------------ | - | 
|                                           
|Cdn GAAP Balance at December 31, 2009       |  |      |  | $ | 5,715,614            |   | $ | (82,387                                | ) | $ | (1,460,283          | ) | $ | 4,172,944    |   | 
|IFRS Adjustments:                           |  |      |  |   |                      |   |   |                                        |   |   |                     |   |   |              |   | 
|Exchangeable limited partnership units      |  | f    |  |   | (112,709             | ) |   |                                        |   |   | 56,893              |   | $ | (55,816      | ) | 
|Trust unit rights incentive plan            |  | f    |  |   | (22,347              | ) |   |                                        |   |   | 13,273              |   |   | (9,074       | ) | 
|Decommissioning liability (ARO) adjustment  |  | e    |  |   |                      |   |   |                                        |   |   | (113,171            | ) |   | (113,171     | ) | 
|Other assets                                |  | g    |  |   |                      |   |   |                                        |   |   | 33,756              |   |   | 33,756       |   | 
|Goodwill impairment                         |  | a    |  |   |                      |   |   |                                        |   |   | (130,440            | ) |   | (130,440     | ) | 
|Income taxes-dual rate                      |  | c    |  |   |                      |   |   |                                        |   |   | (69,011             | ) |   | (69,011      | ) | 
|Cumulative translation adjustment exemption |  | d    |  |   |                      |   |   | 82,387                                 |   |   | (82,387             | ) |   |             |   | 
|                                           
|IFRS Balance at January 1, 2010             |  |      |  | $ | 5,580,558            |   | $ |                                       |   | $ | (1,751,370          | ) | $ | 3,829,188    |   | 
|                                           

Notes to the reconciliation from Canadian GAAP to IFRS

(a) Property, Plant and Equipment

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

i. Pre-Exploration Costs ("Pre-E&E")

Under Canadian GAAP costs incurred prior to having obtained the legal right to explore were capitalized and included in PP&E using the full cost method of
accounting. Under IFRS such expenditures are expensed as incurred. These costs were approximately $1.0 million during 2010 however, as we continue to execute our strategy to obtain early stage
growth assets we expect our Pre-E&E costs to increase.

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

Under Canadian GAAP E&E assets were capitalized using the full cost method of accounting and included in PP&E. Under IFRS our E&E assets are early stage assets
that management has not fully evaluated for technical feasibility and commercial viability. IFRS requires E&E assets to be separately recognized on the face of the balance sheet and these costs are
not subject to depletion. Management has identified approximately $580 million of assets that meet the criteria to be classified as E&E. The balance is comprised primarily of our Kirby oil
sands asset, prior to its disposition on October 1, 2010, and undeveloped lands in Canada and the U.S.

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

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

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

Depreciation and Depletion

Under Canadian GAAP depletion was calculated on a unit of production basis using proved reserves. Under IFRS we have a choice to deplete our D&P assets on a
unit of production basis using either proved or proved plus probable reserves for each CGU. We expect to adopt a policy of depleting D&P assets using proved plus probable reserves for each CGU. As a
result we expect our annual depletion rate to be reduced by approximately 3%, before the consideration of potential impairments.

Under
IFRS an entity recognizes separate depreciable components where part of an asset is significant in value relative to the overall asset and it has a different useful life than the overall asset.
We have assessed our assets and determined we do not have significant components.

Our
office and other assets will continue to be depreciated on a straight-line basis over the assets' useful lives.

ENERPLUS2010 FINANCIAL
SUMMARY27

---



At
January 1, 2010 our accumulated depletion was reset to zero in conjunction with the exemption that allowed companies to allocate their historic net PP&E to their CGUs. There is no change in
our accumulated depreciation balances upon adoption of IFRS.

Derecognition of D&P assets

Under Canadian GAAP full cost accounting gains and losses were not recognized upon disposition of oil and gas assets unless such a disposition would alter the
rate of depletion by 20% or more. Under IFRS gains and losses are recognized based on the difference between the net proceeds from the disposition and carrying value.

(b) Impairments

D&P assets

Under IFRS, testing for D&P asset impairments is completed at a CGU level compared to a country by country basis under Canadian GAAP. When indicators of
impairment exist, the carrying value of each CGU, including goodwill, is compared to its recoverable amount which is defined as the higher of its fair value less cost to sell or value in use. Where
the carrying value exceeds the recoverable amount an impairment loss exists. Impairment losses are first recorded against goodwill within a CGU and the remainder is recorded against oil and
gas assets.

As
at January 1, 2010 no impairment existed on our D&P assets.

E&E assets

Under Canadian GAAP E&E assets were tested for impairment by comparing their recoverable amount to carrying value. Under IFRS E&E assets are subject to an
assessment for impairment indicators at least annually and where indicators exist an impairment test is required. Our E&E asset impairment test compares the E&E assets' carrying value to the sum of
the assets' fair value plus any excess of our D&P assets recoverable amount over their carrying value on a country by country basis.

As
at January 1, 2010 there was no impairment on our E&E assets.

Goodwill

Under Canadian GAAP goodwill was carried on a consolidated basis. On transition to IFRS we allocated the goodwill generated from historic business combinations
to the CGUs that benefited from the synergies of the combination.

Under
Canadian GAAP the goodwill balance was assessed for impairment annually at year-end, or as indicators of impairment arose. Under IFRS goodwill is tested at least annually, in
conjunction with our D&P asset impairment tests.

We
expect to record a goodwill impairment of approximately $130.4 million in our shallow gas CGU at January 1, 2010 with an offset to accumulated deficit.

Reversals of impairment

The reversal of impairment losses on PP&E was not permitted under Canadian GAAP. Under IFRS impairment losses previously recorded are reversed if the conditions
giving rise to the impairment have reversed.

Goodwill
impairments are not reversed in future periods under IFRS, which is consistent with Canadian GAAP.

(c) Deferred tax (previously future income taxes under Canadian GAAP)

Under IFRS all deferred taxes are required to be classified as long-term. As a result we have reclassified $5.0 million of future income taxes previously
classified as current under Canadian GAAP to long term under IFRS.

Our
income trust structure required us to apply a higher deferred tax rate to certain temporary differences under IFRS which resulted in an increase to our deferred tax liability of approximately
$69.0 million at the date of transition. The majority of this increase will reverse on January 1, 2011, upon conversion to a corporation, with a corresponding credit to income.

28      ENERPLUS2010 FINANCIAL
SUMMARY

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A
summary of the tax effect of other opening balance sheet adjustments at January 1, 2010 is as follows:

|($ millions)                                    |  |   | As at
January 1, 2010 |   | 
|----------------------------------------------- |  | - | --------------------- | - | 
|                                               
|Higher deferred tax rate                        |  | $ | 69.0                  |   | 
|Decommissioning liability (ARO)                 |  |   | (42.3                 | ) | 
|Other assets (Marketable securities)            |  |   | 5.0                   |   | 
|Reclass-current tax asset to deferred liability |  |   | (5.0                  | ) | 
|                                               
|Net increase to deferred income tax liability   |  | $ | 26.7                  |   | 
|                                               

(d) Foreign currency translation

Our U.S. operations are translated in the same manner under Canadian GAAP and IFRS. Assets and liabilities of these operations are translated into
Canadian dollars at period end exchange rates, while revenue and expenses are converted using average rates for the period. Gains and losses from the translation into Canadian dollars are deferred and
included in the cumulative translation adjustment ("CTA") which is part of accumulated other comprehensive income.

Upon
adoption of IFRS we utilized an exemption that allowed us to reset the CTA balance to zero instead of retroactively restating it. As a result, at January 1, 2010 the CTA balance in other
comprehensive income is zero.

(e) Decommissioning Liabilities (previously Asset Retirement Obligations under Canadian GAAP)

Under Canadian GAAP and IFRS we recognize a liability for the estimated fair value of the future retirement obligations associated with PP&E. Under Canadian
GAAP the estimates of future cash outflows were discounted using a credit adjusted risk-free rate whereas IFRS recommends a risk-free rate. Additionally, accretion expense
under IFRS is classified as a financing cost whereas it was included within DDA&A under Canadian GAAP.

At
January 1, 2010 we recorded an increase to our ARO liability of approximately $155.4 million. In accordance with the IFRS 1 exemption for full cost oil and gas companies the
offset of $113.1 million, net of $42.3 million in tax, was recorded to accumulated deficit.

(f) Enerplus Exchangeable limited partnership ("EELP") units and Trust Unit Rights

Pursuant to the Fund's trust indenture the Fund's trust units were redeemable at the option of the holder at 85% of the current trading price. Under Canadian
GAAP the Fund's trust units and EELP units were considered permanent equity and included within unitholders' capital. Under IFRS the Fund's trust units are considered puttable financial
instruments however a specific exemption for trust units specifies they are classified as permanent equity within unitholders' capital. This exemption does not apply to instruments that are
convertible into trust units such as the EELP units and trust unit rights. As a result, IFRS requires the EELP units and trust unit rights to be reported as liabilities at their fair value with
changes in fair value recorded to income.

On
January 1, 2010 we recorded a $55.8 million liability representing the redemption value of our outstanding EELP units along with a $112.7 million reduction to our
unitholder's capital and $56.9 million credit to our accumulated deficit to retroactively adjust for the impact of the EELP units.

We
recorded a trust unit rights liability of $9.0 million on January 1, 2010, representing our trust unit rights fair value determined using a binomial lattice option pricing model on
that date. In conjunction with the liability we reduced our contributed surplus by $22.3 million and recorded a credit of $13.3 million to our accumulated deficit.

(g) Other assets

Under Canadian GAAP investments in non-publicly traded securities are carried at cost. Under IFRS all securities, publicly or privately held, must
be carried at fair value and revalued at each reporting date.

As
at January 1, 2010 we recorded an increase in other assets of approximately $39.0 million ($33.7 million net of tax) with the offset recorded against our accumulated deficit.

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Other Considerations

Business Combinations

Under Canadian GAAP transaction costs on business combinations were capitalized. Under IFRS, such costs must be expensed. In addition, any equity purchase
consideration under Canadian GAAP was measured based on the market price over a reasonable period around the announcement date. However, under IFRS equity consideration is measured based on the fair
value on the date the consideration is transferred.

General and Administrative ("G&A") Expenses

Under IFRS we expect to capitalize fewer G&A expenses associated with acquisition and divestiture activities relative to Canadian GAAP. We expect this will
increase our G&A expenses by approximately $0.20/BOE in 2011.

Operating cash flow

The transition to IFRS will impact our operating cash flow as IFRS requires certain costs be expensed that would have been previously capitalized under Canadian
GAAP. These costs have been discussed throughout this section.

Other

In implementing the changes required for the transition to IFRS we have considered the following additional items:

RISK FACTORS AND RISK MANAGEMENT

Commodity Price Risk

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

We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of natural gas and crude oil price volatility. However, we do not
hedge all of our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial derivative instruments that offer only limited protection within selected
price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase. Refer to the "Price Risk Management" section for
further details on our price risk management program.

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Oil and Gas Reserves and Resources Risk

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

Each year, independent engineers evaluate a significant portion of our proved and probable reserves as well as the resources attributable to a significant portion of our
undeveloped land.

McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated 86% of the total proved plus probable value (discounted at 10%) of our Canadian conventional
year-end reserves, 96% of our western U.S. assets and have reviewed the remainder of the reserves which we evaluated internally. In addition, McDaniel reviewed the evaluation of our
contingent resources in the Bakken at Fort Berthold as prepared by Enerplus. Haas Petroleum Engineering Services, Inc. ("Haas") evaluated 100% of the reserves and contingent resources
associated with our Marcellus shale gas property in the eastern United States.

To ensure comparability, all of the independent reserve engineering firms utilized McDaniel's forecast and constant price and cost assumptions as of December 31, 2010
and evaluated our reserves in accordance with NI 51-101.

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

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through equity and debt and as a result, distribute a
significant portion of our cash flow to our unitholders. Continued access to capital is dependent on our ability to optimize our existing assets and to demonstrate the advantages of the acquisition or
development program that we are financing at the time.

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

Marcellus Shale Gas

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

We purchased a non-operated position in 2009 and initially relied upon our partner's expertise, Chief Oil & Gas LLC ("Chief"), with respect to ongoing
development and operations in the Marcellus shale gas region. We monitor costs and results from capital programs adjusting them as we learn and evolve our development plans in the area. As well, in
2010 we acquired an operated interest in the Marcellus with the intention of applying our learnings to properties more directly in our control.

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 obtain transportation capacity on
third party pipelines. New resource plays, such as the North Dakota Bakken and the Marcellus shale gas, generally experience a sharp increase in the amount of production being produced in the area
which could exceed the existing capacity of the gathering and pipeline infrastructure. While 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.

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

Access to Field Services

Our ability to drill, complete and tie-in wells in a timely manner may be impacted by our access to service providers and supplies. Activity levels
in a given area may limit our access to these resources, restricting our ability to execute our capital plans in a timely manner. In addition, field service costs are influenced by market conditions
and therefore can become cost prohibitive.

We
have entered into service contracts for a portion of field services in our US Bakken play that will secure a drilling rig and fracturing services for two years commencing in early 2011. Access to
field services and supplies in other areas of our business will continue to be subject to market availability.

Regulatory Risk & Greenhouse Gas Emissions

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

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

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

Production Replacement Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new
reserves and resources and developing existing reserves and resources. Acquisitions of oil and gas assets depend on our assessment of value at the time of acquisition.

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

Health, Safety and Environmental Risk ("HSE")

Health, safety and environmental risks influence the workforce, operating costs and the establishment of regulatory standards. Enerplus has established a Safety
and Social Responsibility ("S&SR") team that develops standards and systems to manage health, safety, environment, regulatory compliance and stakeholder engagement for the organization.

These management systems include:

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We carry insurance to cover a portion of our property losses, liability and potential losses from business interruption.

The actions of the S&SR team are driven in part by a steering committee which is comprised of executives and senior management. All S&SR risks are reviewed regularly by the
S&SR committee which is comprised of members of the Board of Directors.

Counterparty and Joint Venture Credit Exposure

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

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

See the "Liquidity and Capital Resources" section for further information.

Foreign Currency Exposure

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

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

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

Interest Rate Exposure

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

We monitor the interest rate forward market and have fixed the interest rate on approximately 59% of our debt through our senior unsecured notes and interest
rate swaps.

Changes in Tax and Other Laws

Changes in tax and other laws may adversely affect us and our shareholders. Income tax laws, other laws or government incentive programs relating to the oil and
gas industry may be changed or interpreted in a manner that adversely affects the Company and its shareholders. Tax authorities having jurisdiction over us (whether as a result of our operations or
financing) may change or interpret applicable tax laws, tax treaties or administrative positions in a manner which is detrimental to us or may disagree with how we calculate our income for
tax purposes.

We monitor government correspondence with respect to pending legal changes and work with the industry and professional groups to ensure that our concerns with any changes are
made known to various government agencies. We obtain confirmation from independent counsel and advisors with respect to the interpretation and reporting of material
transactions.

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2011 GUIDANCE

A summary of our 2011 guidance is below which does not include any potential acquisitions or divestments:

|Summary of 2011 Expectations         |  | Target                  |  | Comments                                                                                              | 
|------------------------------------ |  | ----------------------- |  | ----------------------------------------------------------------------------------------------------- | 
|                                    
|Average annual production            |  | 78,000 - 80,000 BOE/day |  |                                                                                                       | 
|Exit rate 2011 production            |  | 80,000 - 84,000 BOE/day |  | Assumes $650 million development capital spending                                                     | 
|2011 production mix                  |  | 53% gas, 47% liquids    |  |                                                                                                       | 
|Average royalty rate                 |  | 20%                     |  | Percentage of gross sales (net of transportation costs)                                               | 
|Operating costs                      |  | $9.20/BOE               |  |                                                                                                       | 
|G&A costs                            |  | $3.30/BOE               |  | Includes non-cash charges of $0.30/BOE (stock option plan) and $0.20/BOE impact of the new IFRS rules | 
|Average interest and financing costs |  | 6%                      |  | Based on current fixed rate contracts and forward interest rates                                      | 
|Development capital spending         |  | $650 million            |  | Within the context of current commodity prices                                                        | 
|Marcellus carry commitment spending  |  | $116 million            |  | Will be reported as a property acquisition                                                            | 
|                                    

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal control over
financial reporting as defined in Rule 13a  15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada by National
Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus
Corporation have concluded that, as at December 31, 2010, 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, 2010 and ended December 31, 2010 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 and its successor issuer, Enerplus Corporation, including our Annual Information Form, is available
under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and forward-looking information statements within the meaning of applicable
securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but
without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: our corporate strategy, including our transition from an income trust to a corporation; our
strategy to deliver both income and growth to investors and our related asset portfolio; future returns to our shareholders from both dividends and from growth in per share production and reserves;
expected oil, natural gas and natural gas liquids production volumes and product mix; future oil and natural gas prices and our commodity risk management programs; cash flow sensitivities to commodity
price, production, foreign exchange and interest rate changes; expected royalty rates and operating, G&A and interest expenses; development capital expenditures and the allocation thereof among our
assets and resource plays; the amount of future abandonment and reclamation costs and asset retirement obligations; future income taxes, our tax pools and the time at which we may pay cash taxes;
future debt and debt-to-cash-flow levels, financial capacity, liquidity and capital resources to fund development capital spending and working capital requirements;
potential asset dispositions; our credit risk mitigation programs; the amount and timing of
future cash dividends that we may pay to our shareholders; future contractual commitments; our transition to IFRS and the impact of that change on our financial results and disclosure; and future
environmental obligations and the costs associated therewith.

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The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions including, without limitation: that we will conduct
our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry
conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and resource volumes; commodity price and cost assumptions; the continued
availability of adequate debt and/or equity financing and cash flow to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors,
expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to
be correct.

The forward-looking information included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information involves 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 including, without limitation: changes in
commodity prices; changes in the demand for or supply of our products; unanticipated operating results, results from our development activities or production declines; changes in tax or environmental
laws, royalty rates or other regulatory matters; changes in our development plans or by third party operators of our properties, increased debt levels or debt service requirements; inaccurate
estimation of our oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of
competitors; reliance on industry partners; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies
described under "Risk Factors and Risk Management" in this MD&A and under "Risk Factors" in the Annual Information Form of Enerplus Resources Fund (the "Fund") dated March 12, 2010,
which is available on our website at www.enerplus.com and on the Fund's SEDAR profile at www.sedar.com and which forms part of the Fund's Form 40-F filed with the SEC on
March 12, 2010 and which is available at www.sec.gov. Additional risk factors will be contained in our Annual Information Form (and corresponding Form 40-F) for the
year ended December 31, 2010, which will be filed in mid-March 2011.

The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

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