EXHIBIT 99.3

---



Management's Discussion and Analysis

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

The following discussion and analysis of financial results is dated February 21, 2013 and is to be read in conjunction with the audited
consolidated financial statements (the "Financial Statements") of Enerplus Corporation ("Enerplus" or the "Company"), as at and for the years ended December 31, 2012
and 2011.

All
amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included with the Financial Statements. Where applicable, natural gas
has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and natural gas liquids ("NGL") have been converted to thousand cubic feet of
gas equivalent ("Mcfe") based on 0.167 bbl:1 Mcfe. The BOE and Mcfe rates are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent
a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1,
utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are presented on a company interest
basis, being the Company's working interest share before deduction of any royalties paid to others, plus the Company's royalty interests. Company interest is not a term defined in Canadian National
Instrument 51-101  Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and may not be comparable to
information produced by other entities.

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 further information.

NON-GAAP MEASURES

The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by IFRS and therefore may not be
comparable with the calculation of similar measures by other entities:

"Payout ratio"is used to analyze operating performance, leverage and liquidity. We calculate payout ratio by dividing dividends to shareholders, net of
our stock dividends and Dividend Reinvestment Plan ("DRIP") proceeds, by funds flow.

"Adjusted payout ratio"is used to analyze operating performance, leverage and liquidity. We calculate our adjusted payout ratio as dividends to
shareholders, net of our stock dividends and DRIP proceeds, plus capital spending (including office capital) divided by funds flow.

"Netback"is used to evaluate operating performance of our crude oil and natural gas assets. The term netback is calculated as oil and gas sales revenue
(net of transportation), less royalties and operating costs.

2012 FOURTH QUARTER OVERVIEW

We delivered significant production and funds flow growth in 2012 ending the year with strong fourth quarter results. Our funds flow improved due to higher production and an
increased weighting to crude oil. Production was also strong in the fourth quarter as Marcellus wells, which had previously been delayed, were brought on-stream. Our annual average and
exit production were within our guidance ranges. Overall our operating results were on track with expectation however net income was negatively impacted by non-cash impairments. We also
added more focus to our asset base with the sale of our Manitoba assets for $218.1 million and the acquisition of an additional interest in our Sleeping Giant property for
$117.6 million. Both assets had similar oil-weighted production. The net proceeds of approximately $100 million went towards debt reduction. We exited the quarter with a
strong balance sheet and a debt-to-funds flow ratio of 1.7 times.

SUMMARY FOURTH QUARTER INFORMATION

In comparing the fourth quarter of 2012 with the same period in 2011:

6      ENERPLUS      2012 FINANCIAL
SUMMARY

---



SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS

|                                         |                                              | Three months ended
December 31, 2012 |        | Three months ended
December 31, 2011
|---------------------------------------- | -------------------------------------------- | ------------------------------------ | ------ | ------------------------------------
|(CDN$ millions, except per unit amounts) |                                              |                                      | Canada |                                     
|                                         |                                              |                                     
|Average Daily Production Volumes         |                                              |                                      |        |                                     
|                                         | Crude oil (bbls/day)                         |                                      |        | 20,713                              
|                                         | Natural gas liquids (bbls/day)               |                                      |        | 3,177                               
|                                         | Natural gas (Mcf/day)                        |                                      |        | 188,628                             
|                                         | Total daily sales (BOE/day)                  |                                      |        | 55,328                              
|Pricing(1)                               |                                              |                                      |        |                                     
|                                         | Crude oil (per bbl)                          |                                      | $      | 72.01                               
|                                         | Natural gas liquids (per bbl)                |                                      |        | 48.09                               
|                                         | Natural gas (per Mcf)                        |                                      |        | 2.76                                
|Capital Expenditures                     |                                              |                                      |        |                                     
|                                         | Capital spending                             |                                      | $      | 49.6                                
|                                         | Property and land acquisitions               |                                      |        | (0.2                                
|                                         | Property dispositions                        |                                      |        | (220.2                              
|Revenues                                 |                                              |                                      |        |                                     
|                                         | Oil and gas sales(1)                         |                                      | $      | 199.8                               
|                                         | Royalties(2)                                 |                                      |        | (29.1                               
|                                         | Commodity derivative instruments gain/(loss) |                                      |        | 17.7                                
|Expenses                                 |                                              |                                      |        |                                     
|                                         | Operating                                    |                                      | $      | 58.6                                
|                                         | General and administrative                   |                                      |        | 14.8                                
|                                         | Equity based compensation                    |                                      |        | 5.2                                 
|                                         | Depletion, depreciation and amortization     |                                      |        | 76.5                                
|                                         | Impairments/(reversals)                      |                                      |        | 331.1                               
|                                         | Current tax expense/(recovery)               |                                      |        | (2.2                                
|                                         |                                              |                                     

ENERPLUS      2012 FINANCIAL
SUMMARY      7

---



2012 OVERVIEW

We increased production by over 9% during 2012, averaging 82,098 BOE/day. We exited the year with production of approximately 85,800 BOE/day for the month of
December. With our oil weighted capital program we successfully grew our crude oil production by 21%, resulting in a crude oil and liquids weighting of 49% compared to 44% in 2011.

Capital
spending and operating costs were in line with expectations totaling $852.8 million and $10.64/BOE respectively. General and Administrative ("G&A") expenses were
consistent with our expectations at $2.61/BOE however equity based compensation was lower than anticipated at $0.51/BOE as we had reduced charges on our long term incentive plans.

Our
funds flow for the year totaled $643.9 million representing an increase of 12% over 2011. Although we experienced lower realized commodity prices in 2012, increased production
and cash gains on our hedging contracts resulted in increased funds flow.

Lower
commodity prices resulted in non-cash impairments of $418.0 million on our developed and producing assets for the year. We also recorded non-cash
impairments of approximately $113.8 million on our exploration and evaluation assets primarily due to land expirations on our less prospective acreage. Although these impairments affect net
income they do not impact funds flow or cash flow from operating activities.

We
continued to enhance our asset base during 2012 with our acquisition and disposition activities. In the fourth quarter we disposed of oil assets in Manitoba with production of
approximately 1,600 BOE/day for proceeds of $218.1 million. Concurrent with this transaction we purchased additional working interests, representing production of approximately
1,550 BOE/day in our Sleeping Giant, Montana crude oil property for $117.6 million, increasing our total working interest in this property to 90%.

During
2012 we completed a number of initiatives to preserve our financial flexibility given our capital spending plans and the low natural gas price environment. In the first half of
2012 we completed an equity offering raising net proceeds of $331 million and also closed a private placement of senior notes for proceeds of approximately $405 million with maturities
extending out 12 years. In July we reduced our monthly dividend to $0.09/share from $0.18/share and introduced a new Stock Dividend Program ("SDP") to provide additional liquidity. We also sold
the majority of our equity investment portfolio during the year for cash proceeds of $146.9 million. Our payout ratio and adjusted payout ratios decreased to 40% and 174% respectively, from 59%
and 212% in 2011 after taking into account the stock dividend program but before acquisitions and divestments. At December 31, 2012 we had approximately $739 million of available
credit on our bank credit facility and a conservative trailing twelve month debt to funds flow ratio of 1.7x.

RESULTS OF OPERATIONS

Production

Production for 2012 was in-line with our expectations averaging 82,098 BOE/day, representing an increase of 9% from production of 75,332 BOE/day in
2011. Our crude oil production increased by 21% over 2011 mainly due to our capital development program which was targeted to increase production at our Fort Berthold, North Dakota crude oil property.
Natural gas volumes were relatively flat year-over-year as increased volumes from our Marcellus assets offset production declines on our conventional natural gas assets in
Canada. Our average daily production for the month of December was approximately 85,800 BOE/day, within our anticipated exit range of 85,000 to 88,000 BOE/day.

Our
crude oil and liquids production weighting increased to 49% for 2012, up from 44% in 2011. We expect a crude oil and liquids weighting of approximately 50% in 2013. Average
daily production volumes for the twelve months ended December 31, 2012 and 2011 are outlined below:

|Average Daily Production Volumes |  | 2012    |  |  | 2011    |  | % Change | 
|-------------------------------- |  | ------- |  |  | ------- |  | -------- | 
|                                 |  |        
|Crude oil (bbls/day)             |  | 36,509  |  |  | 30,181  |  | 21%      | 
|Natural gas liquids (bbls/day)   |  | 3,627   |  |  | 3,306   |  | 10%      | 
|Natural gas (Mcf/day)            |  | 251,773 |  |  | 251,068 |  |         | 
|Total daily sales (BOE/day)      |  | 82,098  |  |  | 75,332  |  | 9%       | 
|                                 |  |        

In 2013 we have reduced our capital spending plans by approximately 20% from 2012 levels given the continued weakness in natural gas prices. As a
result we expect our 2013 production to average between 82,000 BOE/day and 85,000 BOE/day, which at the mid-point of the range would represent a 2% increase over our 2012
average daily production. This guidance does not contemplate future acquisitions or dispositions.

8      ENERPLUS      2012 FINANCIAL
SUMMARY

---



Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, funds flow and financial condition. The following table compares our average
selling prices for 2012 with those of 2011. It also compares the benchmark price indices for the same periods.

|Average Selling Price(1)      |  |   | 2012  |  |  |   | 2011  |  | % Change | 
|----------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                              |  |  
|Crude oil (per bbl)           |  | $ | 78.19 |  |  | $ | 83.48 |  | (6)%     | 
|Natural gas liquids (per bbl) |  |   | 53.01 |  |  |   | 64.99 |  | (18)%    | 
|Natural gas (per Mcf)         |  |   | 2.39  |  |  |   | 3.72  |  | (36)%    | 
|Per BOE                       |  |   | 44.56 |  |  |   | 48.85 |  | (9)%     | 
|                              |  |  

|Average Benchmark Pricing                                        |  |   | 2012  |  |  |   | 2011  |  | % Change | 
|---------------------------------------------------------------- |  | - | ----- |  |  | - | ----- |  | -------- | 
|                                                                 |  |  
|WTI crude oil (US$/bbl)                                          |  | $ | 94.21 |  |  | $ | 95.12 |  | (1)%     | 
|WTI crude oil CDN$ equivalent (CDN$/bbl)                         |  |   | 94.21 |  |  |   | 94.18 |  |         | 
|AECO natural gas  monthly index (CDN$/Mcf)                      |  |   | 2.40  |  |  |   | 3.68  |  | (35)%    | 
|AECO natural gas  daily index (CDN$/Mcf)                        |  |   | 2.39  |  |  |   | 3.62  |  | (34)%    | 
|NYMEX natural gas  monthly NX3 index (US$/Mcf)                  |  |   | 2.80  |  |  |   | 4.07  |  | (31)%    | 
|NYMEX natural gas  monthly NX3 index CDN$ equivalent (CDN$/Mcf) |  |   | 2.80  |  |  |   | 4.03  |  | (31)%    | 
|US/CDN exchange rate                                             |  |   | 1.00  |  |  |   | 0.99  |  | 1%       | 
|                                                                 |  |  

|                                           |  | Twelve months ended |         |  |   |         |  |  |   |         |  |   |         |  |   |         |  |  
|------------------------------------------ |  | ------------------- | ------- |  | - | ------- |  |  | - | ------- |  | - | ------- |  | - | ------- |  | -
|Average Differentials
(US$/bbl or US$/Mcf) |  |                     | 2012    |  |   | 2011    |  |  |   | Q4 2012 |  |   | Q3 2012 |  |   | Q2 2012 |  |  
|                                           | 
|MSW Edmonton  WTI                         |  | $                   | (7.79)  |  | $ | 1.33    |  |  | $ | (3.32)  |  | $ | (7.21)  |  | $ | (10.12) |  | $
|WCS Hardisty  WTI                         |  |                     | (21.03) |  |   | (17.15) |  |  |   | (18.11) |  |   | (21.72) |  |   | (22.87) |  |  
|Brent Futures (ICE)  WTI                  |  |                     | 17.45   |  |   | 15.72   |  |  |   | 21.81   |  |   | 17.22   |  |   | 15.38   |  |  
|AECO monthly  NYMEX                       |  |                     | (0.39)  |  |   | (0.32)  |  |  |   | (0.31)  |  |   | (0.60)  |  |   | (0.40)  |  |  
|                                           | 

Crude Oil and Natural Gas Liquids

Crude oil prices started the year at an average price of US$100.32/bbl in January and finished the year at an average price of US$88.25/bbl in December. Globally, threats to
supply from the continued unrest in the Middle East and low European crude inventories continued to support prices while weak economic conditions negatively impacted prices. The West Texas
Intermediate ("WTI") benchmark price experienced downward pressure relative to Brent prices as the take away capacity at Cushing could not keep pace with rising production and deliveries to
the region.

Crude
differentials widened in 2012 as supply out of Canada and the U.S. Bakken continued to grow. Year-over-year, light differentials for Mixed Sweet
Blend ("MSW") at Edmonton were US$9.12/bbl wider, while heavy differentials for Western Canada Select ("WCS") at Hardisty widened by US$3.88/bbl. Enerplus' 2012 weighted average crude oil stream
differential to WTI represented a discount of US$15.11/bbl compared to US$9.28/bbl in 2011. Downtime at refineries in the spring of 2012 caused differentials to widen significantly, however they did
start to recover later in the year with supply cuts from oil sands upgraders and increases in North American rail transportation capacity. Pipeline capacity continues to be a concern with high
apportionment levels on a number of lines out of Western Canada. We expect these wide differentials to persist until late 2013 and perhaps longer as we await both new pipeline and heavy refining
capacity to come on line.

The
average price received for our crude oil (net of transportation costs) was $78.19/bbl for 2012, a 6% decrease over 2011. In comparison, the WTI benchmark decreased by 1% over
the same period. The difference between the change in WTI and the change in our realized prices is due to wider crude oil differentials in 2012.

ENERPLUS      2012 FINANCIAL
SUMMARY      9

---



Monthly Crude Oil Prices

GRAPHIC

Natural Gas

The AECO monthly index price entered 2012 at $3.02/Mcf and the low occurred in May when it settled at $1.64/Mcf. Natural gas prices fell sharply in early 2012 as supply
outpaced demand resulting in rising inventory levels. As the year progressed, gas prices started to recover as significant coal to gas switching occurred in the power sector providing some relief to
the high gas inventory levels.

During
2012 we sold our natural gas for an average price of $2.39/Mcf (net of transportation costs) which represented a 36% decline from 2011. This decrease was slightly larger
than the change in the AECO and NYMEX indices as we had losses on some of our short-term physical fixed price gas positions. We entered these fixed price contracts at the beginning of the
summer as storage levels appeared to be reaching capacity.

Monthly Natural Gas Prices

GRAPHIC

10      ENERPLUS      2012 FINANCIAL
SUMMARY

---



Price Risk Management

We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions. We have continued to add
crude oil hedge positions for 2013 as our crude oil production currently accounts for approximately 86% of our corporate netback at current commodity prices. As of February 7, 2013 we
have swapped approximately 18,500 bbls/day for 2013 at an average price of US$100.54/bbl, which represents approximately 61% of our forecasted net oil production after royalties. We have
started to add positions for 2014 and have swapped 2,000 bbls/day at $93.33/bbl.

We
have also added a modest level of natural gas price protection however we will continue to look for improvements in prices before adding larger positions. As of
February 7, 2013 we have downside protection representing approximately 28% of our forecasted natural gas production after royalties for 2013. This is comprised of 48,500 Mcf/day
at AECO $3.39/Mcf before premiums. Additionally we have swapped 15,000 Mcf/day at NYMEX US$3.45/Mcf for the first half of 2013. For 2014 we have swapped 10,000 Mcf/day at NYMEX
US$4.03/Mcf. In addition, we continue to hold the physical fixed AECO basis contracts entered into in 2011 that are listed in Note 16.

The
following is a summary of our financial contracts in place at February 7, 2013 expressed as a percentage of our anticipated net production volumes:

|                    |  | Crude Oil (US$/bbl)(1)(2) |                            | AECO Natural Gas(1)
(CDN$/Mcf) |   | NYMEX Natural Gas(1)
(US$/Mcf) | 
|------------------- |  | ------------------------- | -------------------------- | ------------------------------ | - | ------------------------------ | 
|                    |  |                           | Jan 1, 2013 
Dec 31, 2013 |                                |   | Jan 1, 2014 
Dec 31, 2014     | 
|                   
|Purchased Puts      |  |                           |                           |                                |   |                               | 
|%                   |  |                           |                           |                                |   |                               | 
|Sold Puts           |  | $                         | 63.09                      |                                |   |                               | 
|%                   |  |                           | 18%                        |                                |   |                               | 
|Swaps (fixed price) |  | $                         | 100.54                     |                                | $ | 93.33                          | 
|%                   |  |                           | 61%                        |                                |   | 7%                             | 
|Sold Calls          |  | $                         | 130.00                     |                                |   |                               | 
|%                   |  |                           | 12%                        |                                |   |                               | 
|Purchased Calls     |  | $                         | 104.09                     |                                |   |                               | 
|%                   |  |                           | 12%                        |                                |   |                               | 
|                   

Accounting for Price Risk Management

During 2012 we realized cash gains of $18.4 million on our crude oil contracts. In comparison, in 2011 we realized cash losses of $46.5 million on our crude oil
contracts and gains of $13.3 million on our natural gas contracts. The cash gains in 2012 were due to contracts which provided floor protection above market prices. The cash losses in 2011 were
a result of crude oil prices rising above our fixed price swap positions.

As
the forward markets for crude oil and natural gas fluctuate and 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, 2012 the fair value of our crude oil and natural gas contracts represented gains of $50.7 million and
$3.3 million respectively and are recorded as current

ENERPLUS      2012 FINANCIAL
SUMMARY      11

---



deferred
financial assets on our balance sheet. The change in the fair value of our commodity contracts during 2012 represented gains of $70.3 million and $3.3 million, respectively. See
Note 16 for details.

|Risk Management Gains/(Losses)                  |                                    |   |      |      |   |          |          |  |   |       |       |   |            |           
|----------------------------------------------- | ---------------------------------- | - | ---- | ---- | - | -------- | -------- |  | - | ----- | ----- | - | ---------- | ----------
|($ millions, except per unit amounts)           |                                    |   | 2012 |      |   |          | 2011     | 
|                                                |                                    |  
|Cash gains/(losses):                            |                                    |   |      |      |   |          |          |  |   |       |       |   |            |           
|                                                | Crude oil                          |   | $    | 18.4 |   | $        | 1.38/bbl |  |   | $     | (46.5 | ) | $          | (4.22)/bbl
|                                                | Natural gas                        |   |      |     |   | $        |  /Mcf   |  |   |       | 13.3  |   | $          | 0.15/Mcf  
|                                                |                                    |   |      |      |   |          |          |  |   |      
|Total cash gains/(losses)                       |                                    | $ | 18.4 |      | $ | 0.61/BOE |          |  | $ | (33.2 | )     | $ | (1.21)/BOE |           
|Non-cash gains/(losses) on financial contracts: |                                    |   |      |      |   |          |          |  |   |       |       |   |            |           
|                                                | Change in fair value  crude oil   |   | $    | 70.3 |   | $        | 5.26/bbl |  |   | $     | 18.7  |   | $          | 1.70/bbl  
|                                                | Change in fair value  natural gas |   |      | 3.3  |   | $        | 0.04/Mcf |  |   |       | (12.6 | ) | $          | (0.14)/Mcf
|                                                |                                    |   |      |      |   |          |          |  |   |      
|Total non-cash gains/(losses)                   |                                    | $ | 73.6 |      | $ | 2.45/BOE |          |  | $ | 6.1   |       | $ | 0.22/BOE   |           
|                                                |                                    |   |      |      |   |          |          |  |   |      
|Total gains/(losses)                            |                                    | $ | 92.0 |      | $ | 3.06/BOE |          |  | $ | (27.1 | )     | $ | (0.99)/BOE |           
|                                                |                                    |  

Revenues

Crude oil and natural gas revenues in 2012 were $1,339.0 million ($1,365.5 million, net of $26.5 million of transportation costs), similar to 2011 revenues
of $1,343.1 million ($1,363.7 million, net of $20.6 million of transportation costs). Crude oil revenues in 2012 increased due to higher production levels however were partially
offset by lower realized prices. Natural gas and NGL revenues decreased mainly due to lower realized prices.

|Analysis of Sales Revenue(1)($ millions) |  |   | Crude Oil |   |   | NGLs  |   |   | Natural Gas |   |   | Total   |   | 
|---------------------------------------- |  | - | --------- | - | - | ----- | - | - | ----------- | - | - | ------- | - | 
|                                        
|2011 Sales revenue                       |  | $ | 919.6     |   | $ | 78.4  |   | $ | 345.1       |   | $ | 1,343.1 |   | 
|Price variance                           |  |   | (70.7     | ) |   | (15.9 | ) |   | (123.2      | ) |   | (209.8  | ) | 
|Volume variance                          |  |   | 195.9     |   |   | 7.9   |   |   | 1.9         |   |   | 205.7   |   | 
|                                        
|2012 Sales revenue                       |  | $ | 1,044.8   |   | $ | 70.4  |   | $ | 223.8       |   | $ | 1,339.0 |   | 
|                                        

Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Total royalties increased to $268.8 million in 2012 from
$245.2 million during 2011 primarily due to an increased proportion of U.S. production where royalty rates are generally higher than those on our Canadian properties. As a percentage of
oil and gas sales, net of transportation costs, 2012 royalties were 20% compared to 18% in 2011. We are expecting our average royalty rate in 2013 to increase to 21%.

Operating Expenses

Our 2012 operating expenses were $10.64/BOE which was in line with our guidance of $10.70/BOE. Our operating expenses totaled $319.6 million ($10.64/BOE) compared to
$281.2 million ($10.23/BOE) in 2011, representing a 4% increase on a BOE basis.

In
2012 we had higher well servicing and repairs and maintenance costs as poor weather in 2011 delayed some planned maintenance activity into 2012. In Fort Berthold we started collecting
the natural gas and NGL production associated with our oil production and sending it through a third party processing facility which generated additional facility charges during 2012. We also recorded
non-cash mark-to-market losses on our electricity contracts during 2012 compared to gains in the prior year which contributed $0.20/BOE to the
year-over-year variance.

2013
operating expenses are expected to be consistent with 2012 at approximately $10.70/BOE.

12      ENERPLUS      2012 FINANCIAL
SUMMARY

---



Netbacks

The following tables outline our crude oil and natural gas netbacks for 2012 and 2011. The crude oil and natural gas classifications below contain properties according to their
dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such,
the revenue per BOE or per Mcfe may not correspond with the average selling price under the "Pricing" section of this MD&A.

|                                    |  | Year ended December 31, 2012
|----------------------------------- |  | ----------------------------
|Netbacks by Property Type           |  |                             
|                                   
|Average Daily Production            |  |                             
|                                   
|Netback(1) $ per BOE or Mcfe        |  |                             
|                                   
|Revenue(2)                          |  | $                           
|Royalties                           |  |                             
|Cash operating costs                |  |                             
|                                   
|Netback before hedging              |  | $                           
|                                   
|Cash gains/(losses)                 |  |                             
|                                   
|Netback after hedging               |  | $                           
|                                   
|Netback before hedging ($ millions) |  | $                           
|                                   
|Netback after hedging ($ millions)  |  | $                           
|                                   

|
|

|                                    |  | Year ended December 31, 2011
|----------------------------------- |  | ----------------------------
|Netbacks by Property Type           |  |                             
|                                   
|Average Daily Production            |  |                             
|                                   
|Netback(1) $ per BOE or Mcfe        |  |                             
|                                   
|Revenue(2)                          |  | $                           
|Royalties                           |  |                             
|Cash operating costs                |  |                             
|                                   
|Netback before hedging              |  | $                           
|Cash gains/(losses)                 |  |                             
|                                   
|Netback after hedging               |  | $                           
|                                   
|Netback before hedging ($ millions) |  | $                           
|                                   
|Netback after hedging ($ millions)  |  | $                           
|                                   

Our crude oil properties accounted for 86% of our corporate netback before hedging for 2012 compared to 73% for the same period in 2011. Crude oil netbacks per
BOE during 2012 were similar to 2011 as lower realized crude oil prices were offset by cash hedging gains. Natural gas netbacks per Mcfe decreased in 2012 due to lower realized natural
gas prices.

General and Administrative Expenses

G&A expenses during 2012 were $78.3 million or $2.61/BOE compared to $67.6 million or $2.46/BOE in 2011. The increase compared to the prior year was primarily due
to expanding our U.S. operations as well as higher professional and legal fees in 2012. We expect G&A expenses to increase modestly to approximately $2.70/BOE during 2013.

Equity Based Compensation Expenses

Equity based compensation expenses decreased to $15.5 million in 2012 from $26.8 million in 2011. These expenses include charges related to our
long-term incentive plans ("LTI plans") and our stock option plan (see Note 15 for further details). The
costs of our LTI plans are dependent on our share price and can fluctuate from period to period. Our LTI costs were significantly lower in 2012 as a result of the decrease in our share price during
the year.

ENERPLUS      2012 FINANCIAL
SUMMARY      13

---



We
also recorded gains of $0.4 million during 2012 related to equity swaps on our LTI plans that we entered into during the year. Utilizing the equity swaps we effectively fixed
the future settlement cost related to our LTI plans at a weighted average price of $12.49 per share on 1,030,000 shares, representing approximately 65% of the notional shares outstanding under
these plans.

|Equity Based Compensation Expenses($ millions) |  |   | 2012 |   |  |  |   | 2011 | 
|---------------------------------------------- |  | - | ---- | - |  |  | - | ---- | 
|                                               |  |  
|LTI plans expense  cash                       |  | $ | 5.6  |   |  |  | $ | 14.5 | 
|LTI plans equity swap loss/(gain)  non-cash   |  |   | (0.4 | ) |  |  |   |     | 
|Stock option plan  non-cash                   |  |   | 10.3 |   |  |  |   | 12.3 | 
|                                               |  |  
|Total equity based compensation expenses       |  | $ | 15.5 |   |  |  | $ | 26.8 | 
|                                               |  |  

|
|

|Equity Based Compensation Expenses (Per BOE) |  |   | 2012  |   |  |  |   | 2011 | 
|-------------------------------------------- |  | - | ----- | - |  |  | - | ---- | 
|                                             |  |  
|LTI plans expense  cash                     |  | $ | 0.18  |   |  |  | $ | 0.53 | 
|LTI plans equity swap loss/(gain)  non-cash |  |   | (0.01 | ) |  |  |   |     | 
|Stock option plan  non-cash                 |  |   | 0.34  |   |  |  |   | 0.45 | 
|                                             |  |  
|Total equity based compensation expenses     |  | $ | 0.51  |   |  |  | $ | 0.98 | 
|                                             |  |  

Based on our current share price we would expect cash equity based compensation expenses of approximately $0.45/BOE in 2013.

Finance Expense

Interest on our senior notes and bank credit facility in 2012 totaled $53.1 million compared to $47.0 million in 2011. The increase is due to higher average debt
levels in 2012 and an increased weighting of senior notes with higher interest rates after our $405 million private placement of senior notes in May 2012. Non-cash amounts
recorded in finance expense include accretion of decommissioning liabilities, amortization of financing fees and premiums, and unrealized gains and losses resulting from the change in fair value of
our interest rate swaps and the interest component on our cross currency interest rate swap ("CCIRS"). See Note 11 for further details.

|Finance Expense($ millions)                |  |   | 2012 |  |  |   | 2011 | 
|------------------------------------------ |  | - | ---- |  |  | - | ---- | 
|                                           |  |  
|Interest on senior notes and bank facility |  | $ | 53.1 |  |  | $ | 47.0 | 
|Non-cash finance expense                   |  |   | 17.0 |  |  |   | 13.4 | 
|                                           |  |  
|Total finance expense                      |  | $ | 70.1 |  |  | $ | 60.4 | 
|                                           |  |  

At December 31, 2012, after including our underlying derivatives, approximately 71% of our debt was based on fixed interest rates
while 29% had floating interest rates. In comparison, at December 31, 2011 approximately 46% of our debt was based on fixed interest rates and 54% was floating.

14      ENERPLUS      2012 FINANCIAL
SUMMARY

---



Foreign Exchange

We recorded net foreign exchange gains of $17.2 million in 2012 compared to losses of $4.2 million in 2011. We realized foreign exchange gains during 2012 on our
day-to-day US dollar cash transactions in Canada and on our short-term US dollar advances under our credit facility. Our 2012 foreign exchange also includes both
the $18.0 million loss realized upon settlement of our second quarter US$175 million senior note CCIRS settlement and the $18.0 million unrealized gain to remove the
mark-to-market position previously recorded on the swap. See Note 12 for details.

|Foreign Exchange($ millions)       |  |   | 2012  |   |  |  |   | 2011  |   | 
|---------------------------------- |  | - | ----- | - |  |  | - | ----- | - | 
|                                   |  |  
|Realized loss/(gain)               |  | $ | 6.5   |   |  |  | $ | 18.4  |   | 
|Unrealized loss/(gain)             |  |   | (23.7 | ) |  |  |   | (14.2 | ) | 
|                                   |  |  
|Total foreign exchange loss/(gain) |  | $ | (17.2 | ) |  |  | $ | 4.2   |   | 
|                                   |  |  

Capital Investment

Our 2012 capital spending totaled $852.8 million, in-line with our guidance of $850 million and slightly down from $865.7 million in 2011. We
directed approximately 80% of our capital spending towards oil and liquids rich natural gas properties. This included investing $441.6 million on our Fort Berthold crude oil property,
$168.5 million on our Canadian crude oil properties and $69.5 million on our liquids rich deep gas properties in Canada. We also spent $153.6 million on our Marcellus assets
primarily focused on non-operated drilling for lease retention in core areas. Through our capital program we added 57.3 MBOE of proved plus probable reserves, replacing
approximately 190% of our 2012 production.

Property
and land acquisitions during 2012 totaled $185.3 million. The majority of our 2012 spending related to our December 17, 2012 acquisition where we spent
$117.6 million (US$119.5 million) for an additional 20% working interest in our operated leases on our Sleeping Giant Bakken oil property in Montana, increasing our total working
interest to approximately 90%. During the year we continued to invest in undeveloped land to fill in key acreage positions in our core areas with spending of $13.6 million in Canada and
$14.0 million in the Marcellus and Fort Berthold areas within the U.S. We also spent $37.0 million on our Marcellus carry obligation for the year which fully satisfied our carry
commitment.

During
2011 we spent $112.5 million on undeveloped land in Canada and in the U.S. we spent approximately $33.1 million on additional undeveloped land in the
Marcellus surrounding around our existing holdings along with US$111.0 million on our Marcellus carry obligation.

We
plan to spend $685 million on capital projects in 2013 with over 85% of our spending focused on oil and liquids rich natural gas projects. We expect to invest approximately
$340 million on light crude oil development at Fort Berthold, $185 million on our Canadian crude oil properties and $79 million on liquids rich natural gas drilling in the
Canadian Deep Basin region. Our natural gas spending will be focused primarily in the Marcellus where we expect to spend approximately $80 million on non-operated drilling to retain
core acreage. By the end of 2013 we expect to have the majority of our core Marcellus acreage held by production.

Dispositions

Property dispositions in 2012 totaled $275.8 million compared to $641.2 million in 2011. During the year we sold assets in Manitoba for proceeds of
$218.1 million. We also disposed of non-core assets in the U.S. for proceeds of $21.9 million. In aggregate we recognized gains of $83.8 million during the year
on these dispositions.

During
2011 we disposed of approximately 91,000 net acres of our Marcellus interests for proceeds of $567.9 million (US$580 million), and in Canada we disposed of
non-core assets for total proceeds of approximately $61.8 million. We recognized gains of $302.1 million on these disposition activities.

ENERPLUS      2012 FINANCIAL
SUMMARY      15

---



Our
total capital investment activity for 2012 and 2011 is outlined below:

|Capital Investment($ millions) |  |   | 2012   |   |  |  |   | 2011   |   | 
|------------------------------ |  | - | ------ | - |  |  | - | ------ | - | 
|                               |  |  
|Capital spending               |  | $ | 852.8  |   |  |  | $ | 865.7  |   | 
|Office capital                 |  |   | 11.9   |   |  |  |   | 11.3   |   | 
|                               |  |  
|Sub-total                      |  | $ | 864.7  |   |  |  | $ | 877.0  |   | 
|                               |  |  
|Property and land acquisitions |  | $ | 185.3  |   |  |  | $ | 255.2  |   | 
|Property dispositions          |  |   | (275.8 | ) |  |  |   | (641.2 | ) | 
|                               |  |  
|Sub-total                      |  | $ | (90.5  | ) |  |  | $ | (386.0 | ) | 
|                               |  |  
|Total net capital investment   |  | $ | 774.2  |   |  |  | $ | 491.0  |   | 
|                               |  |  

Depletion, Depreciation and Amortization ("DD&A")

DD&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved plus probable reserves. For 2012 DD&A
was $510.8 million or $17.00/BOE compared to $433.4 million or $15.76/BOE in 2011. The increase in our DD&A in 2012 is primarily due to higher production and well costs with respect to
our U.S. operations resulting in higher depletion per BOE.

Impairments

In 2012 we recorded total D&P impairments of $418.0 million, compared to $334.3 million in 2011. The impairments in 2012 related to lower forecast commodity
prices along with increased forecast future development costs with respect to our Canadian CGUs. The impairments recognized in 2011 were also due to lower commodity price forecasts in our Canadian
CGUs. Although these impairments affect net income they do not impact funds flow or cash flow from operating activities. Further fluctuations in forecast prices could cause additional impairments or
impairment reversals going forward.

Exploration
and Evaluation ("E&E") assets are also tested for impairment when there are indicators that suggest their carrying values may exceed their recoverable amount. In 2012 we
recorded E&E impairments totaling $113.8 million of which $65.9 million related to expiring Marcellus leases in West Virginia and Maryland and $47.9 million related to our
Saskatchewan Bakken and Deep Gas E&E assets in Canada. In 2011 we recorded E&E impairments of $35.5 million related to expiring acreage in Canada.

|Impairment Expense($ millions) |  |   | 2012  |  |  |   | 2011  |   | 
|------------------------------ |  | - | ----- |  |  | - | ----- | - | 
|                               |  |  
|D&P impairments                |  | $ | 418.0 |  |  | $ | 334.3 |   | 
|E&E impairments                |  |   | 113.8 |  |  |   | 35.5  |   | 
|E&E impairment reversals       |  |   |      |  |  |   | (10.1 | ) | 
|                               |  |  
|Total impairment expense       |  | $ | 531.8 |  |  | $ | 359.7 |   | 
|                               |  |  

Other Assets

Other assets consist of our portfolio of equity investments in other oil and gas companies. These investments are carried at their estimated fair value with changes in fair
value recorded in other comprehensive income. During the year we sold the majority of our portfolio, consisting primarily of our shares in Laricina Energy Ltd., for net cash proceeds of
$146.9 million resulting in a gain of $47.4 million.

Decommissioning Liabilities

In connection with our operations we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total decommissioning
liabilities 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 decommissioning liability to be $599.7 million at December 31, 2012 compared to $563.8 million at
December 31, 2011. Our overall liability increased year over year as decreases in the liability resulting from our Manitoba non-core asset disposition were more than offset
by increases in liability estimates for some of our non-operated facilities

16      ENERPLUS      2012 FINANCIAL
SUMMARY

---



along
with increases in the liability resulting from changes in the risk-free rate used to calculate the present value of the liability, which decreased to 2.36% at
December 31, 2012 from 2.49% at December 31, 2011. See Note 10 for further information.

We
take an active approach to managing our abandonment, reclamation and remediation obligations. During 2012 we spent $19.9 million
(2011  $21.7 million) on our decommissioning liabilities and we expect to spend approximately $25.8 million in 2013. Our decommissioning
expenditures are expected to be incurred over the next 66 years with the majority between 2022 and 2052. We do not reserve cash or assets for the purpose of funding our future decommissioning
liabilities. Any reclamation or abandonment costs are anticipated to be funded out of cash flow.

Environment

We strive to carry out our activities and operations in compliance with all applicable regulations and good industry practices. Our operations are subject to laws and
regulations concerning pollution, protection of the environment and the handling of hazardous materials and waste. We set corporate targets and mandates to improve environmental performance and
execute environmental initiatives to become more energy efficient and to reduce, reuse and recycle water and minimize waste.

Our
Board of Directors' Safety and Social Responsibility ("S&SR") Committee has oversight and responsibility for the review of our S&SR management system to ensure that our activities
are planned and executed in a safe and responsible manner and to ensure we have adequate systems to support ongoing compliance. We may be subject to environmental and other costs resulting from
unknown and unforeseeable environmental impacts arising from our operations. There are inherent risks of spills and pipeline leaks at our operating sites and clean-up costs may be
significant. However, we have active site inspection, corrosion risk management and asset integrity management programs to help minimize this risk. In addition, we carry environmental insurance to
help mitigate the cost of spills should they occur.

The
ongoing uncertainty surrounding the direction from government on regulations affects our ability to proactively manage potential risks and opportunities associated with greenhouse
gas emissions. We intend to continue to improve energy efficiencies and proactively manage our emissions.

We
use the hydraulic fracturing process in our operations. Government and regulatory agencies continue to frame regulations related to this process. We believe we are in compliance with
all current government regulations in the U.S. and Canada. We would expect to adjust our operations going forward, if necessary, to meet any new or revised regulations when established.

Taxes

We recorded a tax recovery of $61.2 million in 2012 compared to an expense of $32.6 million in 2011. The change in tax expense relates primarily to the decrease
in net income in 2012.

Our
current tax expense was $1.6 million in 2012 compared to $81.2 million in 2011. Current taxes were significantly higher in 2011 due to higher income resulting from the
gain on our Marcellus property disposition. Our current tax expense is comprised mainly of Alternative Minimum Tax ("AMT") payable with respect to our U.S. subsidiary. We expect to recover AMT
in future years as an offset to regular U.S. income taxes otherwise payable.

|Income Tax($ millions)          |  |   | 2012  |   |  |  |   | 2011  |   | 
|------------------------------- |  | - | ----- | - |  |  | - | ----- | - | 
|                                |  |  
|Current tax expense/(recovery)  |  | $ | 1.6   |   |  |  | $ | 81.2  |   | 
|Deferred tax expense/(recovery) |  |   | (62.8 | ) |  |  |   | (48.6 | ) | 
|                                |  |  
|Total tax expense/(recovery)    |  | $ | (61.2 | ) |  |  | $ | 32.6  |   | 
|                                |  |  

We expect to pay U.S. cash taxes of approximately 3% of U.S. cash flow until 2016. We currently do not expect to pay material cash
taxes in Canada until after 2016. These estimates may vary depending on numerous factors including commodity prices, capital spending, tax regulations and acquisition and disposition activity.

ENERPLUS      2012 FINANCIAL
SUMMARY      17

---



Tax Pools

Our estimated tax pools at December 31, 2012 are as follows:

|Pool Type($ millions)    |                                                     |   | 2012  |       |  |   | 2011  |      
|------------------------ | --------------------------------------------------- | - | ----- | ----- |  | - | ----- | -----
|                         |                                                     |  
|Canadian                 |                                                     |   |       |       |  |   |       |      
|                         | COGPE                                               |   | $     | 315   |  |   | $     | 542  
|                         | CDE                                                 |   |       | 316   |  |   |       | 245  
|                         | UCC                                                 |   |       | 375   |  |   |       | 440  
|                         | CEE                                                 |   |       | 216   |  |   |       | 208  
|                         | Non-capital losses                                  |   |       | 488   |  |   |       | 533  
|                         |                                                     |  
|                         |                                                     | $ | 1,710 |       |  | $ | 1,968 |      
|                         |                                                     |  
|U.S.                     |                                                     |   |       |       |  |   |       |      
|                         | AMT                                                 |   | $     | 84    |  |   | $     | 83   
|                         | Tax losses                                          |   |       | 462   |  |   |       | 66   
|                         | Other (including depletable and depreciable assets) |   |       | 1,048 |  |   |       | 1,050
|                         |                                                     |  
|                         |                                                     | $ | 1,594 |       |  | $ | 1,199 |      
|                         |                                                     |  
|Total tax pools          |                                                     | $ | 3,304 |       |  | $ | 3,167 |      
|                         |                                                     |  
|Available capital losses |                                                     | $ | 1,212 |       |  | $ | 1,367 |      
|                         |                                                     |  

At December 31, 2012, we had unused capital losses of $1.2 billion
(2011  $1.4 billion). The available capital losses reflect the balance of unused capital losses available for carry-forward in Canada. These capital
losses have an indefinite carry-forward period however can only be used to offset capital gains.

Net Income/(Loss)

For the year ended 2012 we recorded a net loss of $155.7 million compared to net income of $109.4 million in 2011. The decrease in net income was primarily due to
higher impairments as a result of lower forecast commodity prices, lower gains on asset dispositions,
as well as increased depletion and operating costs. The overall decrease was partially offset by gains on our commodity derivative instruments and lower current tax expense.

Reconciliation of Funds Flow to Net Income per BOE

|                                              |  | Year ended
December 31, 2012 |            | Year ended
December 31, 2011
|--------------------------------------------- |  | ---------------------------- | ---------- | ----------------------------
|Per BOE of production(2)                      |  |                              | Funds
Flow |                             
|                                              |  |                             
|Weighted average sales price(1)               |  | $                            | 44.56      |                             
|Royalties                                     |  |                              | (8.95      | )                           
|Commodity derivative instruments              |  |                              | 0.61       |                             
|Asset disposition gain/(loss)                 |  |                              |           |                             
|Operating costs                               |  |                              | (10.53     | )                           
|General and administrative                    |  |                              | (2.61      | )                           
|Equity based compensation                     |  |                              | (0.18      | )                           
|Interest, foreign exchange and other expenses |  |                              | (1.42      | )                           
|Current tax                                   |  |                              | (0.05      | )                           
|Depletion, depreciation and amortization      |  |                              |           |                             
|Impairments                                   |  |                              |           |                             
|Deferred tax (expense)/recovery               |  |                              |           |                             
|                                              |  |                             
|Total net income/(loss) per BOE               |  | $                            | 21.43      |                             
|                                              |  |                             

18      ENERPLUS      2012 FINANCIAL
SUMMARY

---



SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS

The following table provides a geographical analysis of key operating and financial results for 2012 and 2011.

|                                         |                                              | Year ended December 31, 2012 |        | Year ended December 31, 2011
|---------------------------------------- | -------------------------------------------- | ---------------------------- | ------ | ----------------------------
|(CDN$ millions, except per unit amounts) |                                              |                              | Canada |                             
|                                         |                                              |                             
|Average Daily Production Volumes         |                                              |                              |        |                             
|                                         | Crude oil (bbls/day)                         |                              |        | 20,647                      
|                                         | Natural gas liquids (bbls/day)               |                              |        | 3,244                       
|                                         | Natural gas (Mcf/day)                        |                              |        | 198,356                     
|                                         | Total average daily production (BOE/day)     |                              |        | 56,950                      
|Pricing(1)                               |                                              |                              |        |                             
|                                         | Crude oil (per bbl)                          |                              | $      | 75.21                       
|                                         | Natural gas liquids (per bbl)                |                              |        | 54.86                       
|                                         | Natural gas (per Mcf)                        |                              |        | 2.17                        
|Capital Expenditures                     |                                              |                              |        |                             
|                                         | Capital spending                             |                              | $      | 254.8                       
|                                         | Property and land acquisitions               |                              |        | 13.6                        
|                                         | Property dispositions                        |                              |        | (253.9                      
|Revenues                                 |                                              |                              |        |                             
|                                         | Oil and gas sales(1)                         |                              | $      | 794.1                       
|                                         | Royalties(2)                                 |                              |        | (121.5                      
|                                         | Commodity derivative instruments gain/(loss) |                              |        | 92.0                        
|Expenses                                 |                                              |                              |        |                             
|                                         | Operating                                    |                              | $      | 266.8                       
|                                         | General and administrative                   |                              |        | 63.5                        
|                                         | Equity based compensation                    |                              |        | 15.4                        
|                                         | Depletion, depreciation and amortization     |                              |        | 315.6                       
|                                         | Impairments/(reversals)                      |                              |        | 465.9                       
|                                         | Current income tax expense/(recovery)        |                              |        | (2.1                        
|                                         |                                              |                             

ENERPLUS      2012 FINANCIAL
SUMMARY      19

---



THREE YEAR SUMMARY OF KEY MEASURES AND QUARTERLY FINANCIAL INFORMATION

Oil and gas sales were relatively flat in 2012 as higher production volumes offset the impact of lower realized commodity prices. During 2011 and 2010 higher crude oil prices
were generally offset by declining natural gas prices and lower production levels due to our disposition activity, resulting in flat oil and gas sales during those periods.

Net
income has been affected by fluctuating risk management costs, impairments related to the decrease in natural gas prices, gains on asset dispositions along with changes in
tax provisions.

Cash
and stock dividends were lower in 2012 due to the reduction in our monthly dividend from $0.18 per month to $0.09 per month, effective in July 2012.

Our
long-term debt has increased and our spending has exceeded our cash flows as we continue to invest in our asset base.

|($ millions, except per share amounts) |  |   | 2012    |   |  |  |   | 2011    |  |   | 2010    |   | 
|-------------------------------------- |  | - | ------- | - |  |  | - | ------- |  | - | ------- | - | 
|                                       |  |  
|Oil and gas sales(1)                   |  | $ | 1,339.0 |   |  |  | $ | 1,343.1 |  | $ | 1,300.2 |   | 
|Net income/(loss)                      |  |   | (155.7  | ) |  |  |   | 109.4   |  |   | (179.3  | ) | 
|Per share (Basic)(2)                   |  |   | (0.80   | ) |  |  |   | 0.61    |  |   | (1.02   | ) | 
|Per share (Diluted)(2)                 |  |   | (0.80   | ) |  |  |   | 0.61    |  |   | (1.02   | ) | 
|Funds flow                             |  |   | 643.9   |   |  |  |   | 573.6   |  |   | 729.0   |   | 
|Per share (Basic)(2)                   |  |   | 3.29    |   |  |  |   | 3.19    |  |   | 4.15    |   | 
|Cash and Stock Dividends(3)            |  |   | 301.6   |   |  |  |   | 388.9   |  |   | 384.1   |   | 
|Per share (Basic)(2)(3)                |  |   | 1.54    |   |  |  |   | 2.16    |  |   | 2.19    |   | 
|Total assets                           |  |   | 5,412.2 |   |  |  |   | 5,723.3 |  |   | 5,489.2 |   | 
|Long-term debt, net of cash(4)         |  |   | 1,064.4 |   |  |  |   | 901.5   |  |   | 724.0   |   | 
|                                       |  |  

|
|

|                                          |  |   | Oil and      |  |   | Net           |   | Net Income/(Loss) Per Share
|----------------------------------------- |  | - | ------------ |  | - | ------------- | - | ---------------------------
|(CDN$ millions, except per share amounts) |  |   | Gas Sales(1) |  |   | Income/(Loss) |   |                            
|                                         
|2012                                      |  |   |              |  |   |               |   |                            
|Fourth Quarter                            |  | $ | 360.7        |  | $ | (158.7        | ) | $                          
|Third Quarter                             |  |   | 324.9        |  |   | (63.5         | ) |                            
|Second Quarter                            |  |   | 314.4        |  |   | 100.3         |   |                            
|First Quarter                             |  |   | 339.0        |  |   | (33.8         | ) |                            
|                                          |  |   |              |  |   |               |   |                            
|Total                                     |  | $ | 1,339.0      |  | $ | (155.7        | ) | $                          
|                                         
|2011                                      |  |   |              |  |   |               |   |                            
|Fourth Quarter                            |  | $ | 357.3        |  | $ | (299.4        | ) | $                          
|Third Quarter                             |  |   | 312.9        |  |   | 111.3         |   |                            
|Second Quarter                            |  |   | 354.2        |  |   | 268.0         |   |                            
|First Quarter                             |  |   | 318.7        |  |   | 29.5          |   |                            
|                                          |  |   |              |  |   |               |   |                            
|Total                                     |  | $ | 1,343.1      |  | $ | 109.4         |   | $                          
|                                         

LIQUIDITY AND CAPITAL RESOURCES

During 2012 we completed a number of initiatives to preserve our financial flexibility given our capital spending plans and lower funds flow resulting from depressed natural
gas prices. In the first half of 2012 we completed an equity offering raising net proceeds of $331 million and also closed a private placement of senior notes for proceeds of approximately
$405 million with maturities extending out 12 years.

20      ENERPLUS      2012 FINANCIAL
SUMMARY

---



In
July we reduced our monthly dividend from $0.18 per share to $0.09 per share and also replaced our Dividend Reinvestment Program with a Stock Dividend Program that is available to all
shareholders. The current participation rate is approximately 18% and we expect this rate to increase over time due to the favorable tax attributes of this program.

During
2012 we completed several dispositions which also enhanced our liquidity. We raised net cash proceeds of approximately $146.9 million through the sale of the majority of
our equity investment portfolio, the largest of which was the disposition of all of our shares in Laricina Energy Ltd. In December, we sold our interests in our Manitoba assets for proceeds of
$218.1 million and purchased additional working interests in Sleeping Giant for $117.6 million.

We
are continuing to pursue other measures to support our 2013 capital spending activities including the partial sale or joint venture of our interests in the Duvernay and Montney and
the sale of other non-core producing properties.

Total
debt at December 31, 2012, including the current portion, was $1,069.6 million compared to $907.1 million at December 31, 2011. Total debt
at December 31, 2012 was comprised of $260.9 million of bank indebtedness and $808.6 million of senior notes. We have $739.1 million of available credit on our bank
credit facility at December 31, 2012 and a conservative trailing twelve month debt to funds flow ratio of 1.7x.

Our
working capital deficiency, excluding cash and current deferred financial assets and credits, was $172.4 million at December 31, 2012, decreasing by
$190.2 million from $362.6 million at December 31, 2011. The decrease in our working capital deficit resulted from decreased accounts payable balances due to lower capital
spending compared to the fourth quarter of 2011 as well as lower dividends payable following the reduction of our monthly dividend. We expect to finance our working capital deficit through funds flow
and our bank credit facility.

Our
payout ratio, which is calculated as dividends, net of our stock dividends and DRIP proceeds, divided by funds flow, was 40% for 2012 compared to 59% in 2011. Our adjusted payout
ratio, which is calculated as dividends, net of our stock dividends and DRIP proceeds, plus capital spending and office capital divided by funds flow, was 174% for 2012 compared to 212% in 2011. The
decrease in our payout ratio was a result of increased funds flow over the prior year along with the reduction in our monthly dividend.

Our
key leverage ratios are detailed below:

|Financial Leverage and Coverage                       |  | December 31, 2012 |  |  | December 31, 2011 | 
|----------------------------------------------------- |  | ----------------- |  |  | ----------------- | 
|                                                      |  |                  
|Long-term debt to funds flow (12 month trailing)(1)   |  | 1.7 x             |  |  | 1.6 x             | 
|Funds flow to interest expense (12 month trailing)(2) |  | 12.1 x            |  |  | 12.2 x            | 
|Long-term debt to long-term debt plus equity(1)       |  | 26%               |  |  | 22%               | 
|                                                      |  |                  

On October 31, 2012, our $1.0 billion bank credit facility was extended for a three year term, maturing
October 31, 2015 with the same commercial terms and pricing. At December 31, 2012 we were in compliance with all covenants under our bank credit facility and outstanding
senior notes. Our bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.

Counterparty Credit

Oil and Gas Sales Counterparties

Our oil and gas receivables are with customers in the oil and 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' creditworthiness 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.

ENERPLUS      2012 FINANCIAL
SUMMARY      21

---



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, 2012 we had $62.1 million in mark-to-market assets offset by $35.6 million of mark-to-market liabilities
resulting in a net asset position of $26.5 million.

Dividends

We reported a total of $301.6 million ($1.53/share) in dividends to our shareholders in 2012, of which $23.6 million was non-cash and related to our
SDP. We reduced our monthly dividend from $0.18 per share to $0.09 per share, effective for our July 20, 2012 dividend payment and we will continue to assess our dividend levels with
respect to anticipated funds flow, debt levels, capital spending plans and capital market conditions.

Participation
in the SDP is optional allowing our shareholders to continue to receive cash dividends unless they elect to receive stock dividends. Currently we have a participation rate
of approximately 18% or approximately $3.2 million per month. As with our previous DRIP, the SDP will serve as a source of capital by allowing us to retain cash that would otherwise be paid out
as dividends and extends this option to all of our shareholders.

Commitments

For our Bakken crude oil in the U.S. we have aggregate transportation capacity of approximately 12,500 bbl/day for 2013, 8,500 bbl/day from 2014 to 2016
and 7,500 bbl/day for 2017. This consists of contracted pipeline capacity for 8,500 bbl/day until May 2016 with 7,500 bbl/day of that continuing through
December 2017 as well as a firm commitment for rail capacity to the U.S. Gulf Coast for 6,000 bbl/day during January 2013 and 4,000 bbl/day from February 2013
through January 2014.

In
Canada we have contracted up to 239 MMcf/day of natural gas pipeline capacity, some of it in series, with contract terms that range anywhere from one month to
five years.

Our
Canadian and U.S. office leases expire in 2019. Annual costs of these lease commitments include rent and operating fees. Our commitments, contingencies and guarantees are more
fully described in Note 17.

As
at December 31, 2012 we had the following minimum annual commitments including long-term debt:

|                                    |  |   |         |  |  | Minimum Annual Commitment Each Year |       |  | Total
Committed |      
|----------------------------------- |  | - | ------- |  |  | ----------------------------------- | ----- |  | --------------- | -----
|($ millions)(1)                     |  |   | Total   |  |  |                                     | 2013  |  |                 | 2014 
|                                    |  |  
|Bank credit facility                |  | $ | 261.0   |  |  | $                                   |      |  | $               |     
|Senior unsecured notes(2)           |  |   | 808.6   |  |  |                                     | 45.6  |  |                 | 45.6 
|Transportation commitments          |  |   | 126.5   |  |  |                                     | 49.5  |  |                 | 24.1 
|Processing commitments              |  |   | 1.2     |  |  |                                     | 0.4   |  |                 | 0.3  
|Drilling and completions commitment |  |   | 25.5    |  |  |                                     | 20.1  |  |                 | 5.4  
|Decommissioning liability(3)        |  |   | 659.7   |  |  |                                     | 25.8  |  |                 | 26.0 
|Office leases                       |  |   | 81.8    |  |  |                                     | 13.3  |  |                 | 12.9 
|                                    |  |  
|Total commitments(4)                |  | $ | 1,964.3 |  |  | $                                   | 154.7 |  | $               | 114.3
|                                    |  |  

Shareholders' Capital

On February 8, 2012 we completed a bought deal equity financing of 14,708,500 common shares at a price of $23.45 per share for gross proceeds of
$344.9 million ($330.6 million net of issuance costs). During 2012 a total of 2,816,000 shares (2011  2,510,000)

22      ENERPLUS      2012 FINANCIAL
SUMMARY

---



and
$43.9 million of additional equity (2011  $64.0 million) was issued pursuant to the Stock Dividend Program, our former DRIP and the stock
option plan. For further details see Note 15.

We
had 198,684,000 shares outstanding at December 31, 2012 compared to 181,159,000 shares outstanding at December 31, 2011. The weighted average
basic number of shares outstanding during 2012 was 195,633,000 shares compared to 179,889,000 shares during 2011. At February 20, 2013 we had 199,217,000 shares
outstanding.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS 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 decommissioning liabilities and the application of impairment tests. Revisions or changes
in reserve estimates can have either a positive or a negative impact on net income.

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 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.

Decommissioning Liability

Management calculates the decommissioning liability 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. There are
uncertainties related to decommissioning liabilities 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.

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 and (b) future prices of oil and gas.

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 IFRS ACCOUNTING AND RELATED PRONOUNCEMENTS

Refer to Note 3 in our Financial Statements for a detailed listing of Standards and Interpretations that were issued but not yet effective at
December 31, 2012.

ENERPLUS      2012 FINANCIAL
SUMMARY      23

---



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, NGLs, 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 and crude oil, political stability, transportation facilities, availability of processing, fractionation and refining 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.

Oil and Gas Reserves and Resources Risk

The value of our company is based on, among other things, the underlying value of our 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 reserves engineers evaluate the majority of our proved and probable reserves as well as the resources attributable to a significant portion
of our undeveloped land. All reserves information, including our U.S. reserves, has been prepared in accordance with Canadian National
Instrument 51-101  Standards of Disclosure for Oil and Gas Activities ("NI 51-101") standards. Independent reserve
evaluations have been conducted on approximately 88% of the total proved plus probable value (discounted at 10%) of our reserves at December 31, 2012. McDaniel & Associates
Consultants Ltd. ("McDaniel") evaluated the majority of our Canadian reserves as well as substantially all of the reserves associated with our western U.S. assets and reviewed the
internal evaluation completed by Enerplus on the remaining portion. Haas Petroleum Engineering Services, Inc. ("Haas") evaluated 100% of our Marcellus shale gas assets in the U.S. and provided
the estimate of contingent resources.

The evaluation of contingent resources associated with our leases at Fort Berthold and our Wilrich Deep Gas assets in Canada was conducted by Enerplus and audited
by McDaniel. The contingent resource assessments associated with a portion of our waterflood properties were completed internally by Enerplus qualified reserve evaluators.

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. 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. Nonetheless, our continued access to capital markets is dependent on corporate performance and investor perception of future performance (both corporate and for the oil and
gas sector in general).

Access to Transportation and Processing Capacity

Market access for crude oil, NGLs and natural gas production in Canada and the United States is dependent on our ability to obtain transportation capacity on third party
pipelines, rail and access to processing facilities. Newer resource plays, such as the North Dakota Bakken and the Marcellus shale gas, generally experience a sharp production increase in the area
which could exceed the existing capacity of the gathering, pipeline, processing or rail infrastructure. While third party pipelines, processors and independent rail operators generally expand capacity
to meet market needs, there can be differences in timing between the growth of production and the growth of capacity. There are occasionally operational reasons for curtailing transportation and
processing capacity.

24      ENERPLUS      2012 FINANCIAL
SUMMARY

---



Accordingly,
there can be periods where transportation and processing capacity is insufficient to accommodate all of the production from a given region, causing added expense and/or volume
curtailments for all shippers.

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

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.

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services into 2014, access to
field services and supplies in other areas of our business will continue to be subject to market availability.

Title Defects or Litigation

Unforeseen title defects or litigation may result in a loss of entitlement to production, reserves and resources.

Although we conduct title reviews prior to the purchase of assets these reviews do not guarantee that an unforeseen defect in the chain of title will not arise.
We maintain good working relationships with our industry partners, however disputes may arise from time to time with respect to ownership of rights of certain properties
or resources.

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 continues to seek alignment for the
regulations to be issued in Canada 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 land, reserves and/or
resources and developing existing reserves and resources. Acquisitions of oil and gas assets will depend on our assessment of value at the time of acquisition and ability to secure the acquisitions
generally through a competitive bid process.

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 impact our workforce, operating costs and the establishment of regulatory standards. Certain government and regulatory agencies in Canada
and the United States have begun investigating the potential risks associated with hydraulic fracturing. We expect regulatory frameworks will be amended or continue to emerge in this regard and
regulations may be amended. The impact of such changes on our business could increase our cost of compliance and the risk of litigation and environmental liability.

Enerplus has established a Safety and Social Responsibility ("S&SR") team that develops standards and systems to manage health safety and environmental risks,
regulatory compliance and stakeholder engagement for the organization. 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. We also carry insurance to cover a portion of our property losses, liability and
potential losses from business interruption.

ENERPLUS      2012 FINANCIAL
SUMMARY      25

---



Counterparty and Joint Venture Credit Exposure

The low natural gas price environment increases the risk of bad debts related to our joint venture and industry partners. A failure of our counterparties to perform their
financial or operational obligations may adversely affect our operations and financial position.

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 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 when the Canadian dollar weakens relative to the U.S. dollar.

We have hedged our foreign currency exposure on our US$175 million, US$54 million and a portion of our US$225 million senior 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 or our U.S. operations.

Interest Rate Exposure

We have exposure to movements in interest rates and credit markets as changing interest rates affect our borrowing costs and value of investments such as our shares as well as
other equity investments.

We monitor the interest rate forward market and have fixed the interest rate on approximately 71% of our debt through our senior notes and interest
rate swaps.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may be changed in a manner that adversely affects us or our security holders. Tax
authorities may interpret applicable tax laws, tax treaties or administrative positions differently than we do or may disagree with how we calculate our income for tax purposes in a manner which is
detrimental to us and our security holders.

We monitor developments 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 legal counsel and advisors with respect to the interpretation and reporting of material
transactions.

Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts listed in Note 16 and are based on forward markets as at February 7, 2013. To the extent
crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.

|Sensitivity Table(2)                                       |  |   | Estimated Effect on
2013 Funds Flow
per Share(1) | 
|---------------------------------------------------------- |  | - | ------------------------------------------------ | 
|                                                          
|Change of $0.50 per Mcf in the price of AECO natural gas   |  | $ | 0.16                                             | 
|Change of US$5.00 per barrel in the price of WTI crude oil |  | $ | 0.13                                             | 
|Change of 1,000 BOE/day in production                      |  | $ | 0.06                                             | 
|Change of $0.01 in the US$/CDN$ exchange rate              |  | $ | 0.05                                             | 
|Change of 1% in interest rate                              |  | $ | 0.02                                             | 
|                                                          

26      ENERPLUS      2012 FINANCIAL
SUMMARY

---



2013 GUIDANCE

A summary of our 2013 guidance is below. This guidance does not include any potential acquisitions or divestments.

|Summary of 2013 Expectations                                   |  | Target                                     | 
|-------------------------------------------------------------- |  | ------------------------------------------ | 
|                                                              
|Average annual production                                      |  | 82,000 - 85,000 BOE/day                    | 
|Exit rate production                                           |  | 84,000 - 88,000 BOE/day                    | 
|Capital spending                                               |  | $685 million                               | 
|Production mix (volumes)                                       |  | 50% crude oil and liquids, 50% natural gas | 
|Average royalty rate (% of gross sales, net of transportation) |  | 21%                                        | 
|Operating costs                                                |  | $10.70/BOE                                 | 
|G&A expenses  cash                                            |  | $2.70/BOE                                  | 
|Equity based compensation expenses  cash                      |  | $0.45/BOE                                  | 
|Cash taxes (% of U.S. funds flow)                              |  | ~3%                                        | 
|Average interest and financing costs                           |  | 5%                                         | 
|                                                              

INTERNAL CONTROLS AND PROCEDURES

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 under 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, 2012, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal control over financial
reporting during the period beginning on October 1, 2012 and ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.

ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our current 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.

ENERPLUS      2012 FINANCIAL
SUMMARY      27

---



FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and forward-looking 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: expected 2013 average production volumes and the anticipated production mix; the results from our drilling
program and the timing of related production; future oil and natural gas prices and our commodity risk management programs; future royalty rates on our production; anticipated cash and
non-cash G&A and financing expenses; operating costs; capital spending levels in 2013 and its impact on our production level and land holdings; potential future asset impairments and
reversals; the amount of our future abandonment and reclamation costs and decommissioning liabilities; future environmental expenses; our future U.S. cash taxes; deferred income taxes, our tax
pools and the time at which we may pay Canadian cash taxes; future debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial
capacity, liquidity and capital resources to fund capital spending and working capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; the amount and
timing of future debt and equity issuances and expected use of proceeds therefrom; and the amount and timing, and use of proceeds from, future asset dispositions.

The forward-looking information contained in this MD&A reflects several material factors, 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 funds flow to fund our capital and operating requirements and dividend payments as needed; the availability of third party services;
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 is not a guarantee 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 capital spending activities or production declines;
changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital 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 third party service providers; a failure to complete planned asset dispositions on the terms anticipated or at all; 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 in our other public filings.

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.

28      ENERPLUS      2012 FINANCIAL
SUMMARY

---



QuickLinks