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