Enerplus Exceeds Operating & Financial Targets for 2013

All financial information contained within this news release has been prepared 
in accordance with U.S. GAAP including comparative figures pertaining to 
Enerplus' 2012 results. This news release includes forward-looking statements 
and information within the meaning of applicable securities laws.  Readers are 
advised to review the "Forward-Looking Information and Statements" at the 
conclusion of this news release. Readers are also referred to "Information 
Regarding Reserves, Resources and Operational Information", "Notice to U.S. 
Readers" and "Non-GAAP Measures" at the end of this news release for 
information regarding the presentation of the financial, reserves, contingent 
resources and operational information in this news release. A full copy of our 
2013 Financial Statements and MD&A are available on our website at 
www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR 
website at www.sec.gov. 
CALGARY, Feb. 21, 2014 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) 
(NYSE: ERF) is pleased to announce fourth quarter 2013 results as well as 2013 
year-end operating and financial results. 
2013 KEY TAKEAWAYS: 


        --  Funds flow per share grew by 14%
        --  Production grew by 9%, exceeding guidance in spite of non-core
            asset sales
        --  Proved plus probable reserves were up 17% year-over-year,
            replacing 284% of 2013 production
        --  Capital spending, operating costs and general and
            administrative costs were all reduced
        --  Debt to funds flow ratio at year-end improved to 1.4x

4th Quarter 2013:
        --  Production continued to grow during the fourth quarter of 2013
            averaging 94,167 BOE per day, up 7% from the previous quarter
            and 10% compared to the same period in 2012. Production during
            the month of December averaged 99,569 BOE per day, ahead of our
            exit guidance of 95,000 BOE per day. Marcellus production
            exceeded our expectations, producing 170 MMcf per day during
            the month of December including the additional working
            interests acquired in late November.  Crude oil and natural gas
            liquids volumes were virtually unchanged quarter over quarter,
            despite the sale of 900 barrels per day of crude oil in
            Canada.  As a result of the higher volumes from the Marcellus,
            our production weighting to natural gas increased to 56% during
            the fourth quarter.
        --  We invested $223 million in capital projects during the
            quarter, with over two thirds of the spending directed to oil
            projects. A total of 18 net wells were drilled, with 19 net
            wells brought on-stream.
        --  Funds flow totaled $181 million during the fourth quarter, down
            8% from the previous quarter. Despite the growth in production
            volumes, a widening of crude oil differentials resulted in a
            decrease of almost 20% in our average realized crude oil price
            compared to the previous quarter.
        --  Cash operating costs and general and administrative expenses
            per BOE were both down compared to the third quarter, averaging
            $10.46 and $2.28 per BOE, respectively.
        --  We closed a number of transactions during the fourth quarter
            including the acquisition of additional working interests in
            our Marcellus natural gas properties for $158 million.  Through
            this acquisition, we added 17,000 net acres in existing
            properties in northeast Pennsylvania with approximately 42 MMcf
            per day of natural gas production.
        --  We also closed the sale of non-core producing assets in Canada
            for proceeds of $104 million.  In addition, we entered into an
            agreement to sell our undeveloped Montney acreage in British
            Columbia for $135 million, after adjustments, of which $66
            million closed during the quarter with the remainder closed in
            January of 2014.

2013 SUMMARY:
        --  We delivered annual production growth of 9% in 2013, exceeding
            both our annual and exit production forecasts for the year.
            Daily production averaged 89,800 BOE, ahead of guidance of
            89,000 BOE per day. Total oil production increased by 5% in
            2013 to average 38,250 barrels per day, despite the sale of
            2,700 BOE per day of non-core oil production.
        --  Natural gas production increased by 15% to average 288 MMcf per
            day for the year, representing 54% of our annual production
            volumes. Strong well performance in the Marcellus combined with
            the acquisition of additional working interests in December
            helped to drive this result.
        --  Funds flow grew by 17% year-over-year to $754 million due to
            the increase in production volumes, lower costs and an increase
            in commodity prices. On a per share basis, this was a 14%
            increase.
        --  Capital spending came in slightly lower than our forecast of
            $685 million, totaling $681 million. Approximately 70% of our
            spending was directed to our crude oil assets with the majority
            invested at Fort Berthold, North Dakota. We invested 82% of our
            budget on drilling and completion activities, with 62 net wells
            drilled and brought on-stream across our asset base.
        --  We continued to concentrate our portfolio throughout 2013. We
            sold $365 million of non-core assets, redeploying $245 million
            to increase our working interests in our crude oil waterflood
            portfolio and in the Marcellus.  This also includes additional
            acreage acquired in the Wilrich, Marcellus and Bakken/Three
            Forks plays. Our net acquisition and divestment activities
            realized gross proceeds of $120 million in 2013.
        --  Our capital efficiencies improved again in 2013.  Based upon
            our capital spending and the growth in production volumes from
            the fourth quarter of 2012 to the same period in 2013, this
            reflects a capital efficiency of approximately $26,000 per
            daily BOE.
        --  With the increase in funds flow, a reduction in capital
            spending and improved capital efficiencies, our adjusted payout
            ratio improved to 114% in 2013 including participation in our
            Stock Dividend Plan ("SDP"). Monthly dividends to shareholders
            were maintained throughout the year, totaling $1.08 per share
            and represented 23% of funds flow including the SDP.
        --  As a result of the growth in funds flow and the net proceeds
            from our divestment activities, our financial flexibility
            increased in 2013. Approximately 80% of our bank credit
            facility was undrawn and our trailing twelve month
            debt-to-funds-flow ratio fell to 1.4 times at year-end, down
            from 1.7 times at year-end 2012.
        --  Our proved plus probable ("2P") company interest reserves
            increased by 17% at year-end, replacing 284% of our 2013
            average daily production.
        --  Finding and development costs including future development
            capital ("FDC") were $11.28 per BOE. When divided by our
            corporate netback of $27.40 per BOE, this reflects a 2.4x
            recycle ratio.
        --  Finding, development and acquisition costs, including FDC, were
            $8.36 per BOE.
        --  The net present value of our future net revenues discounted at
            10% before tax increased by 7% in 2013 to approximately $5
            billion.
    SELECTED FINANCIAL   Three months ended December   Twelve months ended
    RESULTS                          31,                      December 31,
                              2013              2012        2013      2012
    Financial (000's)                                                     
    Funds Flow            $180,741          $200,411    $754,233  $644,523
    Cash and Stock
    Dividends               54,665            53,572     216,864   301,560
    Net Income              29,626            34,637      47,976 (270,697)
    Debt Outstanding -
    net of cash          1,022,308         1,064,365   1,022,308 1,064,365
    Capital Spending       223,035           160,934     681,437   853,455
    Property and Land
    Acquisitions           173,387           121,391     244,837   185,337
    Property
    Divestitures           168,050           220,135     365,135   275,771
                                                                          
    Debt to Trailing 12
    Month Funds Flow          1.4x              1.7x        1.4x      1.7x
                                                                          
    Financial per
    Weighted Average
    Shares Outstanding                                                    
    Funds Flow               $0.89             $1.01       $3.76     $3.29
    Net Income                0.15              0.17        0.24    (1.38)
    Weighted Average
    Number of Shares
    Outstanding (000's)    202,257           198,256     200,567   195,633
                                                                          
    Selected Financial
    Results per BOE(1)
    (2)                                                                   
    Oil & Natural Gas
    Sales(3)                $43.79            $45.86      $48.11    $44.56
    Royalties               (7.46)            (7.28)      (8.06)    (7.06)
    Production Taxes        (2.07)            (2.26)      (2.15)    (1.89)
    Commodity Derivative
    Instruments               1.90              2.04        0.81      0.61
    Operating Costs        (10.46)            (9.14)     (10.50)   (10.51)
    General and
    Administrative          (2.28)            (2.34)      (2.54)    (2.61)
    Share Based
    Compensation            (1.06)            (0.03)      (0.71)    (0.18)
    Interest and Other
    Expenses                (1.51)            (1.45)      (1.71)    (1.42)
    Taxes                     0.01              0.08      (0.24)    (0.05)
    Funds Flow              $20.86            $25.48      $23.01    $21.45
                                                                  
                                                                  
    SELECTED OPERATING   Three months ended December   Twelve months ended
    RESULTS                          31,                  December 31,
                              2013              2012        2013      2012
    Average Daily
    Production(2)                                                         
        Crude oil
        (bbls/day)          37,731            38,597      38,250    36,509
        NGLs (bbls/day)      3,813             3,576       3,472     3,627
        Natural gas
        (Mcf/day)          315,739           259,904     288,423   251,773
        Total (BOE/day)     94,167            85,490      89,793    82,098
                                                                          
        % Crude Oil &
        Natural Gas
        Liquids                44%               49%         46%       49%
                                                                          
    Average Selling
    Price(2)(3)                                                           
        Crude oil (per
        bbl)               $ 77.77           $ 76.75     $ 83.99   $ 78.19
        NGLs (per bbl)       54.26             47.31       52.25     53.01
        Natural gas (per
        Mcf)                  3.26              3.01        3.26      2.39
                                                                          
    Net Wells drilled           18                11          62        75
    (1) Non-cash amounts have been excluded.
    (2) Based on Company interest production volumes.
    (3) Net of oil and gas transportation costs, but before royalties and
        the effects of commodity derivative instruments.
                          Three months ended December   Twelve months ended
                                                  31,          December 31,
                            2013                 2012     2013         2012
    Average Benchmark                                                      
    Pricing
    WTI crude oil         $97.46               $88.18   $97.97       $94.21
    (US$/bbl)
    AECO- monthly index     3.16                 3.06     3.16         2.40
    (CDN$/Mcf)
    AECO- daily index       3.53                 3.22     3.17         2.39
    (CDN$/Mcf)
    NYMEX- monthly NX3      3.63                 3.36     3.67         2.80
    index (US$/Mcf)
    USD/CDN exchange        1.05                 0.99     1.03         1.00
    rate
    SHARE TRADING SUMMARY                        CDN* - ERF   U.S.** - ERF
    For the twelve months ended December 31,         (CDN$)          (US$)
    2013
    High                                             $19.96         $18.79
    Low                                              $12.26         $12.03
    Close                                            $19.30         $18.18

* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
    2013 DIVIDENDS PER SHARE      CDN$   US$(1)
    First Quarter Total          $0.27    $0.27
    Second Quarter Total         $0.27    $0.26
    Third Quarter Total          $0.27    $0.26
    Fourth Quarter Total         $0.27    $0.26
    Total                        $1.08    $1.05
    (1) US$ dividends represent CDN$ dividends converted at the relevant
        foreign exchange rate on the payment date.
    2013 PRODUCTION & CAPITAL SPENDING      
     
                             Q4                                        2013
    Crude Oil &            2013             2013          2013      Capital
    NGLs                Average   Annual Average          Exit     Spending
    (bbls/day)       Production       Production   Production*   ($million)
    Canada               19,561           20,663        18,958        172.9
    United States        21,983           21,059        21,455        316.2
    Total Crude
    Oil & NGLs
    (bbls/day)           41,544           41,722        40,413       $489.1
    Natural Gas
    (Mcf/day)                                                              
    Canada              165,114          175,876       161,965        113.7
    United States       150,625          112,547       192,967         78.7
    Total Natural
    Gas (Mcf/day)       315,739          288,423       354,932       $192.4
    Company Total
    (BOE/day)            94,167           89,793        99,569       $681.4

*December month
    2013 NET DRILLING ACTIVITY***
                                                    Wells
                                                  Pending                     Dry &
    Crude     Horizontal   Vertical   Total   Completion/         Wells   Abandoned
    Oil            Wells      Wells   Wells      Tie-in *   On-stream**       Wells
    Canada          20.9         .2    21.1           1.8          18.6           -
    United
    States          20.3          -    20.3           4.5          24.7           -
    Total
    Crude
    Oil             41.2         .2    41.4           6.3          43.3           -
    Natural
    Gas                                                                            
    Canada          11.5          -    11.5           6.2           5.6           -
    United
    States           9.3          -     9.3           5.6          12.7           -
    Total
    Natural
    Gas             20.8          -    20.8          11.8          18.2           -
    Company
    Total           62.0         .2    62.2          18.1          61.5           -

* Wells drilled during the year that are pending potential completion/tie-in 
or abandonment as at December 31, 2013.
** Total wells brought on-stream during the year regardless of when they were 
drilled.
*** Table may not add due to rounding.

ASSET ACTIVITY

Our 2013 capital program was focused in our four core areas - the U.S. 
Bakken/Three Forks, the Marcellus, our Canadian crude oil waterfloods and our 
deep gas opportunities within the Deep Basin region of Alberta. Our single 
largest capital investment was once again in North Dakota where we allocated 
45% of our capital budget to continue development of the Bakken and Three 
Forks zones. Our program was focused on improving capital efficiencies through 
a reduction in well costs and increased productivity. We continued to evolve 
our well completion design in North Dakota throughout 2013 and through these 
changes and focused cost management; we were able to deliver a 50% increase in 
the average 30 day initial production rate while still reducing total well 
costs by 8% on average in 2013.  The changes have driven a 40% improvement in 
capital efficiencies year-over-year. We grew production from this region by 
over 30% in 2013. We also added 25 MMBOE of 2P reserves at a cost of $19.74 
per BOE including future development capital. With an average netback of 
approximately $53 per BOE in 2013, this delivered a 2.7x recycle ratio.

We continued to invest in the Marcellus throughout 2013, concentrating our 
drilling activity within the most economic areas in northeastern Pennsylvania. 
Well costs improved year-over-year decreasing by approximately 20% through a 
combination of pad drilling and lower costs. As well, production rates 
continued to exceed our expectations throughout the year. A total of 9 net 
wells were drilled in 2013, with 13 net wells tied in and brought on-stream. 
Despite a widening of the basis differentials in the region given constrained 
take-away capacity, we continue to see robust economics from our drilling 
program. The majority of our drilling activity was focused in Bradford, 
Susquehanna and Sullivan counties with average 30 day initial production rates 
increasing by approximately 60% year-over-year to almost 10 MMcf per day in 
these counties. Production during the month of December averaged 170 MMcf per 
day of natural gas, driven by the acquisition of additional working interests 
and the tie-in of 6 net wells in the fourth quarter.  Through our development 
and acquisition activities, we added 411 Bcf of 2P reserves at a cost of $0.91 
per Mcf including future development capital. This reflects a 2.2x recycle 
ratio based upon our average netback of $2.00 per Mcf from the Marcellus in 
2013. Our Marcellus production represents approximately 50% of both our 
corporate natural gas volumes and our 2P natural gas reserves.

Our activities in Canada were predominately directed to our crude oil 
waterflood projects where we advanced our enhanced oil recovery project at 
Medicine Hat and continued with our drilling and optimization programs at our 
Freda Lake, Pembina, and Giltedge properties.  We also drilled 4 net wells in 
the Wilrich and in the Duvernay, we drilled two vertical wells, one horizontal 
re-entry and spud one horizontal well in 2013 to advance our understanding of 
these emerging plays.

RESERVES AND CONTINGENT RESOURCE ASSESSMENT:

Our total 2P reserves increased by over 17% year-over-year, driven by 
significant reserve additions in the Marcellus and also in our Bakken/Three 
Forks properties in North Dakota. At December 31, 2013, Enerplus' independent 
reserve evaluators had assessed 406 million BOE of 2P company interest 
reserves attributable to our asset base. Additional information on our 2013 
reserves can be found in our news release dated February 3, 2014.

In addition to the 2P reserves, an assessment of the additional resource 
potential within a portion of our asset base has identified 363 MMBOE of 
economic, best estimate contingent resources ("contingent resources") as of 
December 31, 2013. This quantity of contingent resources is essentially 
unchanged from year-end 2012, despite converting approximately 70 MMBOE of 
contingent resources to reserves. Based upon our forecast production volumes 
for 2014, this would represent approximately 10 years of organic reserve 
replacement potential currently existing within a portion of our portfolio 
today.

Our contingent resource assessment includes:
        --  39 MMBOE of contingent resources attributable to both the
            Bakken and Three Forks at Fort Berthold. 18 MMBOE of previously
            assessed contingent resources were converted to reserves in
            2013 and 23 MMBOE of new contingent resources were added
            primarily associated with the Three Forks formation. This
            assessment assumes a well density of two wells per drilling
            spacing unit within the Bakken and two wells per spacing unit
            within the first bench of the Three Forks formation only.  We
            believe further upside potential may exist through both
            increased drilling density and also drilling into the lower
            benches in the Three Forks.
        --  59 MMBOE of contingent resources attributable to improved oil
            recovery ("IOR") and enhanced oil recovery ("EOR") in our
            Canadian waterflood assets. Approximately 4 MMBOE of previously
            assessed contingent resources were converted to reserves in
            2013.
        --  1.3 Tcf of contingent resources associated with our Marcellus
            natural gas assets. We added approximately 290 Bcf of
            contingent resources associated with the acquisition of
            additional working interests and reclassified 258 Bcf of
            contingent resources to reserves as a result of our successful
            drilling activity.
        --  253 Bcf of contingent resources associated with our Wilrich
            deep gas assets in Canada. Approximately 30 Bcf of contingent
            resources were reclassified to reserves in 2013 as a result of
            our successful drilling activities.

At this time, there has been no assessment of the resource potential within 
our Duvernay land position.

2014 Outlook

We expect to produce an average of 96,000 - 100,000 BOE/day in 2014, an 
increase of 9% year-over-year or 8% per share using the mid-point of this 
range. We expect continued growth from our U.S. oil properties at Fort 
Berthold where we anticipate that average annual production will increase by 
approximately 30% in 2014, driving our light crude oil volumes to 67% of our 
total oil production. Total crude oil and natural gas liquids production is 
expected to increase by approximately 12%. Natural gas production is expected 
to increase by 7% averaging over 300 MMcf per day with the majority of the 
growth attributable to the Marcellus. Our U.S. assets are anticipated to 
account for over 50% of our corporate production volumes in 2014. The 
production mix is expected to remain at approximately 48% crude oil and 
natural gas liquids and 52% natural gas although continued outperformance in 
the Marcellus could push the natural gas share higher.

The improvement in asset quality and operational performance along with our 
focus on cost reductions and productivity enhancements has resulted in a 
significant improvement in capital efficiencies across our portfolio. We plan 
to build on these improvements in 2014 to deliver another year of profitable 
growth complemented by a meaningful dividend to our investors. Our plans 
include investing $760 million in capital projects in 2014 with two thirds of 
our budget directed to oil projects in North Dakota and in our Canadian 
waterfloods. The remainder of our budget will be directed to our core natural 
gas assets in the Marcellus and in the Deep Basin region as we move into 
development in the Wilrich and continue to evaluate the Duvernay. Given that 
approximately 55% of our planned capital spending is in the U.S., continued 
weakness in the Canadian dollar could put upward pressure on our 2013 spending 
which is reported in Canadian dollars, although it would also have a positive 
effect on reported revenues.

Hedging Update

We continue to hedge a portion of our crude oil and natural gas production in 
order to provide downside protection to our funds flow estimates.  As of 
February 4, 2014, we have swapped approximately 59% of our net crude oil 
production for 2014, after royalties, at an average price of US$94.02 per 
barrel. We also have downside protection on approximately 40% of our 
forecasted natural gas production after royalties for 2014.  Full details on 
our hedging contracts are contained within our 2013 Annual MD&A & Financial 
Statements which have been filed on SEDAR and EDGAR.

Changes to Board of Directors

We are pleased to announce that Ms. Hilary Foulkes has joined the Board of 
Directors of Enerplus.  Ms. Foulkes has over 30 years of experience within the 
Canadian oil and gas industry focused in the areas of exploration, development 
and investment banking. She is a professional geologist and earned a Bachelor 
of Science (Honours, Earth Sciences) from the University of Waterloo.

Live Conference Call

Ian C. Dundas, President and CEO, will host a conference call today, February 
21, 2014 at 9:00 a.m. MT (11:00 a.m. ET) to discuss these results. Details of 
the conference call are as follows:
    Date:          Friday, February 21, 2014
    Time:          9:00 am MT/11:00 am ET
    Dial-In:       647-427-7450
                   1-888-231-8191
    Audiocast:     http://www.newswire.ca/en/webcast/detail/1298449/1432621

To ensure timely participation in the conference call, callers are encouraged 
to dial in 15 minutes prior to the start time to register for the event. A 
podcast of the conference call will also be available on our website for 
downloading following the event.  A telephone replay will be available for 30 
days following the conference call and can be accessed at the following 
numbers:
    Dial-In:      416-849-0833   
                  1-855-859-2056 (toll free)
    Passcode:     58756618

Electronic copies of our 2013 year-end MD&A and Financial Statements, along 
with other public information including investor presentations, are available 
on our website at www.enerplus.com.  For further information, please contact 
Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.

INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL INFORMATION

Currency and Accounting Principles

All amounts in this news release are stated in Canadian dollars unless 
otherwise specified. All financial information in this news release has been 
prepared and presented in accordance with U.S. GAAP, except as noted below 
under "Non-GAAP Measures".

Barrels of Oil Equivalent

This news release also contains references to "BOE" (barrels of oil 
equivalent). Enerplus has adopted the standard of six thousand cubic feet of 
gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs.  
BOEs may be misleading, particularly if used in isolation.  The foregoing 
conversion ratios are based on an energy equivalency conversion method 
primarily applicable at the burner tip and do not represent a value 
equivalency at the wellhead. Given that the value ratio based on the current 
price of oil as compared to natural gas is significantly different from the 
energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be 
misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and 
"million barrels of oil equivalent", respectively.

Presentation of Production and Reserves Information

Under U.S. GAAP oil and gas sales are generally presented net of royalties and 
U.S. industry protocol is to present production volumes net of royalties.  
Under IFRS and Canadian industry protocol oil and gas sales and production 
volumes are presented on a gross basis before deduction of royalties.   In 
order to continue to be comparable with our Canadian peer companies, the 
summary results contained within this news release presents our production and 
BOE measures on a before royalty company interest basis.

All production volumes and revenues presented herein are reported on a 
"company interest" basis, before deduction of Crown and other royalties, plus 
Enerplus' royalty interest. Unless otherwise specified, all reserves volumes 
in this news release (and all information derived therefrom) are based on 
"company interest reserves" using forecast prices and costs. "Company interest 
reserves" consist of "gross reserves" (as defined in NI 51-101), being 
Enerplus' working interest before deduction of any royalties), plus Enerplus' 
royalty interests in reserves. "Company interest reserves" are not a measure 
defined in NI 51-101 and do not have a standardized meaning under NI 51-101. 
Accordingly, our company interest reserves may not be comparable to reserves 
presented or disclosed by other issuers. Our oil and gas reserves statement 
for the year ended December 31, 2013, which will include complete disclosure 
of our oil and gas reserves and other oil and gas information in accordance 
with NI 51-101, is contained within our Annual Information Form for the year 
ended December 31, 2013 ("our AIF") which is available on our website at 
www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, 
our AIF forms part of our Form 40-F that is filed with the U.S. Securities and 
Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also 
urged to review the Management's Discussion & Analysis and financial 
statements filed on SEDAR and as part of our Form 40-F on EDGAR concurrently 
with this news release for more complete disclosure on our operations.

Contingent Resource Estimates

This news release contains estimates of "contingent resources". "Contingent 
resources" are not, and should not be confused with, oil and gas reserves. 
"Contingent resources" are defined in the Canadian Oil and Gas Evaluation 
Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as 
of a given date, to be potentially recoverable from known accumulations using 
established technology or technology under development, but which are not 
currently considered to be commercially recoverable due to one or more 
contingencies. Contingencies may include factors such as ultimate recovery 
rates, legal, environmental, political and regulatory matters or a lack of 
markets. It is also appropriate to classify as "contingent resources" the 
estimated discovered recoverable quantities associated with a project in the 
early evaluation stage. All of our contingent resource estimates are economic 
using established technologies and under current commodity price assumptions 
used by our independent reserve evaluators. Enerplus expects to develop these 
contingent resources in the coming years however it is too early in their 
development for these resources to be classified as reserves at this time. 
There is no certainty that we will produce any portion of the volumes 
currently classified as "contingent resources". The "contingent resource" 
estimates contained herein are presented as the "best estimate" of the 
quantity that will actually be recovered, effective as of December 31, 2013.  
A "best estimate" of contingent resources means that it is equally likely that 
the actual remaining quantities recovered will be greater or less than the 
best estimate, and if probabilistic methods are used, there should be at least 
a 50% probability that the quantities actually recovered will equal or exceed 
the best estimate.

For additional information regarding the primary contingencies which currently 
prevent the classification of our disclosed "contingent resources" associated 
with our Marcellus shale gas properties, our Fort Berthold properties, our 
Wilrich natural gas properties and a portion of our Canadian crude oil 
properties as reserves and the positive and negative factors relevant to the 
"contingent resource" estimates, see our AIF, a copy of which is available 
under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which 
is available under our EDGAR profile at www.sec.gov.

See "Non-GAAP Measures" below.

NOTICE TO U.S. READERS

The oil and natural gas reserves information contained in this news release 
has generally been prepared in accordance with Canadian disclosure standards, 
which are not comparable in all respects to United States or other foreign 
disclosure standards. Reserves categories such as "proved reserves" and 
"probable reserves" may be defined differently under Canadian requirements 
than the definitions contained in the United States Securities and Exchange 
Commission (the "SEC") rules. In addition, under Canadian disclosure 
requirements and industry practice, reserves and production are reported using 
gross (or, as noted above, "company interest") volumes, which are volumes 
prior to deduction of royalty and similar payments. The practice in the United 
States is to report reserves and production using net volumes, after deduction 
of applicable royalties and similar payments. Canadian disclosure requirements 
require that forecasted commodity prices be used for reserves evaluations, 
while the SEC mandates the use of an average of first day of the month price 
for the 12 months prior to the end of the reporting period.  Additionally, the 
SEC prohibits disclosure of oil and gas resources in SEC filings, whereas 
Canadian issuers may disclose oil and gas resources. Resources are different 
than, and should not be construed as reserves. For a description of the 
definition of, and the risks and uncertainties surrounding the disclosure of, 
contingent resources, see "Information Regarding Reserves, Resources and 
Operational Information" above.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and statements 
("forward-looking information") within the meaning of applicable securities 
laws. The use of any of the words "expect", "anticipate", "continue", 
"estimate", "guidance", "objective", "ongoing", "may", "will", "project", 
"should", "believe", "plans", "intends", "budget", "strategy" and similar 
expressions are intended to identify forward-looking information. In 
particular, but without limiting the foregoing, this news release contains 
forward-looking information pertaining to the following: Enerplus' asset 
portfolio; future capital and development expenditures and the allocation 
thereof among our assets; future development and drilling locations, plans and 
costs; the performance of and future results from Enerplus' assets and 
operations, including anticipated production levels, expected ultimate 
recoveries and decline rates; future growth prospects, acquisitions and 
dispositions; the volumes and estimated value of Enerplus' oil and gas 
reserves and contingent resource volumes and future commodity price and 
foreign exchange rate assumptions related thereto; the life of Enerplus' 
reserves; future funds flow and debt-to-funds flow levels; potential asset 
acquisitions and dispositions; rates of return on Enerplus' capital program; 
Enerplus' tax position; sources of funding of Enerplus' capital program; and 
future costs, expenses and royalty rates.

The forward-looking information contained in this news release reflects 
several material factors and expectations and assumptions of Enerplus 
including, without limitation: that Enerplus will conduct its operations and 
achieve results of operations as anticipated; that Enerplus' 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 
Enerplus' reserve and resource volumes; commodity price and cost assumptions; 
the continued availability of adequate debt and/or equity financing, cash flow 
and other sources to fund Enerplus' capital and operating requirements as 
needed; and the extent of its liabilities. Enerplus believes 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 news release 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 realized prices for Enerplus' 
products; changes in the demand for or supply of Enerplus' products; 
unanticipated operating results, results from development plans or production 
declines; changes in tax or environmental laws, royalty rates or other 
regulatory matters; changes in development plans by Enerplus or by third party 
operators of Enerplus' properties; increased debt levels or debt service 
requirements; inaccurate estimation of Enerplus' oil and gas reserves and 
resources volumes; limited, unfavourable or a lack of access to capital 
markets; increased costs; a lack of adequate insurance coverage; the impact of 
competitors; reliance on industry partners; and certain other risks detailed 
from time to time in Enerplus' public disclosure documents (including, without 
limitation, those risks identified in our AIF and Form 40-F described above).

The purpose of certain financial outlook information included in this news 
release, including with respect to our 2014 guidance for funds flow, is to 
communicate our current expectations as to our performance in 2014.  Readers 
are cautioned that it may not be appropriate for other purposes. The 
forward-looking information contained in this news release speaks only as of 
the date of this news release, and none of Enerplus or its subsidiaries assume 
any obligation to publicly update or revise them to reflect new events or 
circumstances, except as may be required pursuant to applicable laws.

NON-GAAP MEASURES

In this news release, we use the terms "funds flow", "adjusted payout ratio", 
"capital efficiency", "recycle ratio" and "netback" as measures to analyze 
operating performance, leverage and liquidity. "Funds flow" is calculated as 
net cash generated from operating activities but before changes in non-cash 
operating working capital and asset retirement obligation expenditures. 
"Adjusted payout ratio" is calculated as cash dividends to shareholders, net 
of our stock dividends and DRIP proceeds, plus capital spending (including 
office capital) divided by funds flow. "Capital efficiency" is calculated as 
the change in production from the fourth quarter of the previous year to the 
fourth quarter of the current year divided by total capital expenditures from 
the fourth quarter of the previous year up to and including the third quarter 
of the current year. "Netback" is calculated as oil and gas revenues after 
deducting royalties, operating costs and transportation expenses. A "recycle 
ratio" is calculated as finding and development costs divided by operating 
netback.

Enerplus believes that, in addition to net earnings and other measures 
prescribed by U.S. GAAP, the terms "funds flow", "adjusted payout ratio", 
"capital efficiency", "netback" and "recycle ratio" are useful supplemental 
measures as they provide an indication of the results generated by Enerplus' 
principal business activities. However, these measures are not measures 
recognized by U.S. GAAP and do not have a standardized meaning prescribed by 
U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be 
comparable to similar measures presented by other issuers.

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation



SOURCE  Enerplus Corporation 
To view this news release in HTML formatting, please use the following URL: 
http://www.newswire.ca/en/releases/archive/February2014/21/c5790.html 
CO: Enerplus Corporation
ST: Alberta
NI: OIL ERN  
-0- Feb/21/2014 11:00 GMT
 
 
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