SYS-CON MEDIA Authors: Mat Mathews, PR.com Newswire, David Smith, Tim Crawford, Kevin Benedict

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Enerplus Exceeds Production Guidance for 2013 and Delivers Record Reserve Replacement

This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review "Forward-Looking Information and Statements" at the conclusion of this news release. Readers are also referred to "Information Regarding Reserves 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 and operational information in this news release.

CALGARY, Feb. 3, 2014 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce production and reserve results for the year ended 2013. Highlights include:

2013 PRODUCTION

  • Annual average production grew by over 9% in 2013 to average 89,800 BOE per day, ahead of our expectations of 89,000 BOE/day.

  • Production during the month of December averaged 99,600 BOE per day, exceeding our expectations due to continued outperformance in the Marcellus, which averaged 170 MMcf per day during the month.

  • Fourth quarter 2013 production averaged 94,200 BOE per day. As a result of the Marcellus performance, the natural gas weighting increased to 56% during the quarter.

2013 YEAR-END RESERVES

  • Proved plus probable company interest ("2P") reserves grew by over 17% to 406 MMBOE. On a per share basis, 2P reserves increased by 15% year-over-year.

  • Added 78 MMBOE of 2P reserves through our development programs, including technical and economic revisions, replacing 238% of 2013 annual production.  Approximately 30% of the reserve additions were from crude oil.

  • Added a total of 93 MMBOE of 2P reserves, including technical and economic revisions and net acquisition and development activity, replacing 284% of production in 2013.  83% of the total reserve additions were from natural gas.

  • Capital spending for the year was an estimated $681.4 million, slightly less than our forecast of $685 million. Approximately two thirds of our capital was invested in oil projects in 2013.

  • 2P finding and development ("F&D") costs including future development capital ("FDC") decreased by over 50% to $11.28 per BOE.  This represents a recycle ratio of 2.4 times based upon an estimated operating netback of $27.40 per BOE in 2013.

  • 2P finding, development and acquisition ("FD&A") costs per BOE were $8.36 per BOE including FDC, down over 60% year-over-year.  Our three year FD&A costs for 2P reserves, including FDC, are $14.66 per BOE.

  • A total of 24.4 MMbbls of 2P crude oil reserves were added through our acquisition and capital spending activities, including technical and economic revisions, reflecting a 175% oil production replacement and offsetting the disposition of 10 MMbbls of oil reserves during the year.

  • 2P natural gas reserves increased by 43% to 1.2 Tcf with the addition of 463 Bcf associated with our development, acquisition and divestment activities. The majority of the increase in 2P natural gas reserves is attributable to the Marcellus where we added 268 Bcf of 2P reserves through our capital development activities, including technical and economic factors, and 143 Bcf through acquisitions. Total Marcellus 2P reserves at year-end increased to 601 Bcf and now represent 50% of our total 2P natural gas reserves, up from 27% at year-end 2012.

  • 12.1 MMBOE of 2P reserves were sold during 2013 at an average cost of $33.72 per BOE.

  • 26.9 MMBOE of 2P reserves were purchased during 2013, the majority of which is attributable to the acquisition of additional working interests in the Marcellus, at an average cost of $11.25 per BOE.

  • 2P reserve life index remains essentially unchanged at 10.8 years.

INDEPENDENT RESERVES EVALUATION

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 89.5% of the total proved plus probable value (before tax, discounted at 10%) of our reserves at December 31, 2013. McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated 74% of our Canadian reserves and 100% of the reserves associated with our U.S. oil assets. McDaniel also reviewed the internal evaluation completed by Enerplus on the remaining 26% of our Canadian assets. Netherland, Sewell & Associates, Inc. ("NSAI") evaluated all of our U.S. natural gas assets.

The following reserves information sets out our company interest reserves volumes at December 31, 2013 by production type and reserve category under McDaniel's forecast price scenarios. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit associated with a property. Company interest reserves consist of gross reserves, which are before the deduction of any royalties, plus Enerplus' royalty interests in reserves.  It should be noted that tables may not add due to rounding.

See "Information Regarding Reserves and Operational Information" at the end of this news release for information regarding the presentation of company interest reserves.

RESERVES SUMMARY

Enerplus' 2P reserves increased by 60.2 million BOE to 406.0 million BOE at year-end 2013, up from 345.8 million at year-end 2012. The majority of reserve additions were associated with our U.S. properties as a result of our drilling and acquisition activities. These assets now represent 58% of total 2P reserves. Proved reserves as a percentage of total 2P reserves remained at 65% year-over-year.

Reserves Summary Light &
Medium
Oil
(Mbbls)
Heavy Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Company Interest              
  Proved producing 64,108 26,700 90,808 7,348 354,385 212,770 192,681
  Proved developed non-producing 805 136 941 145 8,486 72,320 14,553
  Proved undeveloped 22,883 3,980 26,863 1,475 46,959 126,342 57,221
  Total proved 87,795 30,816 118,611 8,967 409,830 411,431 264,455
  Total probable 62,371 11,264 73,635 5,757 183,744 189,430 141,587
Proved plus Probable 150,166 42,080 192,246 14,723 593,574 600,861 406,042
Gross              
  Proved producing 64,006 26,689 90,695 7,166 338,646 212,770 189,764
  Proved developed non-producing 805 136 941 144 8,417 72,320 14,541
  Proved undeveloped 22,879 3,980 26,859 1,422 43,215 126,342 56,540
  Total proved 87,689 30,806 118,495 8,732 390,280 411,431 260,844
  Total probable 62,340 11,260 73,600 5,629 174,445 189,430 139,875
Proved plus Probable 150,029 42,066 192,095 14,361 564,725 600,861 400,720
Net              
  Proved producing 53,604 21,407 75,011 5,398 305,107 170,423 159,663
  Proved developed non-producing 700 106 806 104 6,335 57,893 11,614
  Proved undeveloped 18,654 3,053 21,707 1,172 42,789 101,084 46,858
  Total proved 72,957 24,566 97,523 6,674 354,231 329,400 218,136
  Total probable 50,388 8,588 58,976 4,459 158,767 151,530 115,152
Proved plus Probable 123,345 33,154 156,499 11,134 512,998 480,930 333,288
               

RESERVES RECONCILIATION

The following tables outline the changes in Enerplus' proved, probable and proved plus probable reserves, on a company interest basis, from December 31, 2012 to December 31, 2013:

Proved Reserves - Company Interest Volumes (Forecast Prices)
 
CANADA Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Reserves at
 Dec. 31, 2012
36,246 31,521
67,767
6,887 361,158
    -
134,847
Acquisitions 1,580               - 1,580 19 1,676               - 1,879
Dispositions (7,105)               - (7,105) (599) (5,999)               - (8,703)
Discoveries               -               -               -               -               -               -               -
Extensions & improved
 recovery
1,511 1,528 3,039 196 24,172
           -
7,264
Economic factors 491 55 546 (29) (3,058)               - 8
Technical revisions (105) 828 722 878 32,791               - 7,065
Production (3,404) (3,115) (6,520) (1,023) (64,195)               - (18,241)
Proved Reserves at
 Dec. 31, 2013

29,214

30,816
60,030 6,330 346,545        
      -
124,118

UNITED STATES Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Reserves at
 Dec. 31, 2012
56,993
   -  
56,993 2,349 52,748 146,127 92,488
Acquisitions 30               -   30 2 12 117,668 19,645
Dispositions               -                 -                 -                 -                 -                 -                 -  
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
5,188               -   5,188 255 5,177 168,634 34,412
Economic factors (556)               -   (556) 2 (1,126) (17,140) (3,598)
Technical revisions 4,368               -   4,368 273 12,778 30,917 11,924
Production (7,442)               -   (7,442) (245) (6,305) (34,775) (14,533)
Proved Reserves at
 Dec. 31, 2013

58,581
              -   58,581 2,637 63,285 411,431 140,337
   

               
TOTAL ENERPLUS Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Reserves at
 Dec. 31, 2012
93,239 31,521 124,760 9,236 413,906
146,127
227,335
Acquisitions 1,610               -   1,610 21 1,688 117,668 21,524
Dispositions (7,105)               -   (7,105) (599) (5,999)               -   (8,703)
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
6,699 1,528 8,227 451
29,349
168,634 41,675
Economic factors (65) 55 (10) (26) (4,183) (17,140) (3,590)
Technical revisions 4,262 828 5,090 1,151 45,569 30,917 18,989
Production (10,846) (3,115) (13,961) (1,267) (70,499) (34,775) (32,774)
Proved Reserves at
 Dec. 31, 2013
87,795 30,816 118,611 8,967 409,830 411,431 264,455

Probable Reserves - Company Interest Volumes (Forecast Prices)
 
CANADA Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Probable Reserves at
 Dec. 31, 2012
12,810 10,991 23,801 3,144 171,526               -   55,533
Acquisitions 290               -   290 3 283               -   340
Dispositions (2,775)               -   (2,775) (214) (2,164)               -   (3,350)
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
687 1,751 2,438 70 8,489               -   3,923
Economic factors (13) 57 45 (18) (937)               -   (129)
Technical revisions (1,320) (1,536) (2,856) (421) (32,227)               -   (8,649)
Production               -                 -                 -                 -                 -                 -                 -  
Probable Reserves at
 Dec. 31, 2013
9,679 11,264 20,943 2,564 144,970               -   47,668
   

UNITED STATES Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Probable Reserves at
 Dec. 31, 2012
43,111               -   43,111 2,243 27,202 78,373 62,950
Acquisitions 681               -   681 40 266 25,686 5,046
Dispositions               -                 -                 -                 -                 -                 -                 -  
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
14,477               -   14,477 986 12,973 89,619 32,562
Economic factors 8               -   8 2 (19) (8,877) (1,473)
Technical revisions (5,585)               -   (5,585) (78) (1,647) 4,629 (5,166)
Production               -                 -                 -                 -                 -                 -                 -  
Probable Reserves at
 Dec. 31, 2013
52,692               -   52,692 3,193 38,774 189,430 93,919
               
               
TOTAL ENERPLUS Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Probable Reserves at
 Dec. 31, 2012
55,921 10,991 66,912 5,387 198,728 78,373 118,482
Acquisitions 971               -   971 43 548 25,686 5,386
Dispositions (2,775)               -   (2,775) (214) (2,164)               -   (3,350)
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
15,164 1,751 16,916 1,056 21,462 89,619 36,485
Economic factors (5) 57 53 (16) (956) (8,877) (1,602)
Technical revisions (6,905) (1,536) (8,441) (499) (33,874) 4,629 (13,815)
Production               -                 -                 -                 -                 -                 -                 -  
Probable Reserves at Dec. 31, 2013 62,371 11,264 73,635 5,757 183,744 189,430 141,587

Proved Plus Probable Reserves - Company Interest Volumes (Forecast Prices)
 
CANADA Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Plus Probable
 Reserves at Dec. 31, 2012
49,056 42,512 91,568 10,031 532,684               -   190,380
Acquisitions 1,870               -   1,870 23 1,959               -   2,219
Dispositions (9,880)               -   (9,880) (813) (8,163)               -   (12,053)
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
2,198 3,279 5,477 266 32,661               -   11,186
Economic factors 478 113 591 (46) (3,995)               -   (121)
Technical revisions (1,426) (708) (2,134) 457 564               -   (1,583)
Production (3,404) (3,115) (6,520) (1,023) (64,195)               -   (18,241)
Proved Plus Probable
 Reserves at Dec. 31, 2013
38,893 42,080 80,973 8,894 491,515               -   171,787
   

UNITED STATES Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil (Mbbls) Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Plus Probable
 Reserves at Dec. 31, 2012
100,104               -   100,104 4,592 79,950 224,500 155,438
Acquisitions 711               -   711 42 277 143,354 24,691
Dispositions               -                 -                 -                 -                 -                 -                 -  
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
19,665               -   19,665 1,241 18,150 258,253 66,974
Economic factors (548)               -   (548) 4 (1,145) (26,017) (5,071)
Technical revisions (1,217)               -   (1,217) 196 11,131 35,545 6,758
Production (7,442)               -   (7,442) (245) (6,305) (34,775) (14,533)
Proved Plus Probable
 Reserves at Dec. 31, 2013
111,273               -   111,273 5,829 102,059 600,861 234,256
               
TOTAL ENERPLUS Light &
Medium
Oil
(Mbbls)
Heavy
Oil
(Mbbls)
Total Oil
(Mbbls)
Natural
Gas
Liquids
(Mbbls)
Natural
Gas
(MMcf)
Shale
Gas
(MMcf)
Total
(MBOE)
Proved Plus Probable
 Reserves at Dec. 31, 2012
149,160 42,512 191,672 14,623 612,634 224,500 345,817
Acquisitions 2,581               -   2,581 64 2,236 143,354 26,910
Dispositions (9,880)               -   (9,880) (813) (8,163)               -   (12,053)
Discoveries               -                 -                 -                 -                 -                 -                 -  
Extensions & improved
 recovery
21,864 3,279 25,143 1,507 50,811 258,253 78,160
Economic factors (70) 113 43 (42) (5,139) (26,017) (5,192)
Technical revisions (2,643) (708) (3,351) 652 11,695 35,545 5,174
Production (10,846) (3,115) (13,961) (1,267) (70,499) (34,775) (32,774)
Proved Plus Probable
 Reserves at Dec. 31, 2013
150,166 42,080 192,246 14,723 593,574 600,861 406,042
               

FUTURE DEVELOPMENT CAPITAL

Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the evaluators' best estimate of the capital required to bring the proved and proved plus probable reserves on production. The aggregate of the exploration and development costs incurred in the most recent year and the change during the year in estimated future development costs generally reflect the total finding and development costs related to reserve additions for that year.

The increase in FDC year-over-year is a result of the increase in the number of undeveloped drilling locations at Fort Berthold, the Marcellus, in the Wilrich and in our Canadian waterflood properties.

The following is a summary of the independent reserve evaluators' estimated FDC required to bring the total proved and proved plus probable probable reserves on production:

Future Development Capital Proved
Reserves
Proved Plus
Probable Reserves
($ millions)  
2014                             479                             558
2015                             390                             518
2016                               31                             439
2017                               31                             376
2018                               19                               40
Remainder                               51                               65
Total FDC Undiscounted                           1,001                           1,996
Total FDC Discounted at 10%                             889                           1,667

F&D AND FD&A COSTS - including future development capital
 
($ millions except for per BOE amounts) 2013 2012 2011 3 Year
Proved Plus Probable Reserves        
         
Finding & Development Costs        
  Capital Expenditures $   681.4 $  852.8 $  829.8 $ 2,364.0
  Net change in Future Development Capital $    200.0 $  534.6 $  435.9 $ 1,170.5
  Company Interest Reserve additions (MMBOE) 78.1 57.3 48.2 $    183.6
  F&D costs ($/BOE) $   11.28 $  24.21 $  26.26 $    19.25
          
Finding,  Development & Acquisition Costs        
  Capital expenditures and net acquisitions $   561.1 $  726.4 $  370.2 $ 1,657.7
  Net change in Future Development Capital $    216.6 $  509.1 $  402.7 $ 1,128.4
  Company Interest Reserve additions (MMBOE) 93.0 53.9 43.2 $    190.1
  FD&A costs ($/BOE) $      8.36 $  22.92 $  17.89 $    14.66
         
Proved Reserves        
         
Finding & Development Costs        
  Capital Expenditures $    681.4 852.8 829.8 $ 2,364.0
  Net change in Future Development Capital $  (106.4) 248.3 230.7 $    372.6
  Company Interest Reserve additions (MMBOE) 57.1 38.4 31.5 $    127.0
  F&D costs ($/BOE) $    10.08 $  28.67 $  33.67 $    21.55
          
Finding, Development & Acquisition Costs        
  Capital expenditures and net acquisitions $   561.1 726.4 370.2 $ 1,657.7
  Net change in Future Development Capital $  (112.8) 241.3 213.0 $    341.5
  Company Interest Reserve additions (MMBOE) 69.9 36.6 28.9 $    135.4
  FD&A costs ($/BOE) $      6.41 $  26.44 $  20.18 $    14.77
 

FORECAST PRICE ASSUMPTIONS

The estimated reserves volumes and the net present values of future net revenues ("NPV") at December 31, 2013 were based upon forecast crude oil and natural gas pricing assumptions prepared by McDaniel as of January 1, 2014. These prices were applied to the reserves evaluated by McDaniel and NSAI, along with those evaluated internally by Enerplus and reviewed by McDaniel. The base reference prices and exchange rates used by McDaniel are detailed below.

While the near-term oil and natural gas price assumptions used by our independent reserve evaluators at January 1, 2014 increased, the long-term price outlooks decreased when compared to the price assumptions used at December 31, 2012.  As a result, despite a 17% increase in our 2P reserves at December 31, 2013, the estimated before tax NPV using a 10% discount increased by only 7%.

McDaniel January 2014 Forecast Price Assumptions
  WTI
Crude Oil
US$/bbl
Light
Crude Oil(1)
Edmonton
CDN$/bbl
Hardisty
Heavy Oil
12o API
CDN$/bbl
Henry Hub
Gas Price
US$/MMBtu
Natural Gas
30 day spot
@ AECO
CDN$/MMBtu
Exchange
Rate
CDN$/US$
             
2014 95.00 95.00 67.50 4.25 4.00 0.950
2015 95.00 96.50 70.40 4.50 4.25 0.950
2016 95.00 97.50 71.20 4.75 4.55 0.950
2017 95.00 98.00 71.50 5.00 4.75 0.950
2018 95.30 98.30 71.80 5.25 5.00 0.950
Thereafter     **     **     **     **     ** 0.950
(1) Edmonton Light Sweet 40 degree API, 0.3% sulphur content crude.
**  Escalation varies after 2018.
 

NET PRESENT VALUE OF FUTURE PRODUCTION REVENUE

The following table provides an estimate of the net present value of Enerplus' future production revenue after deduction of royalties, estimated future capital and operating expenditures, before income taxes. It should not be assumed that the present value of estimated future cash flows shown below is representative of the fair market value of the reserves.

Net Present Value of Future Production Revenue - Forecast Prices and Costs (before tax)
Reserves at December 31, 2013, ($ Millions, discounted at) 0% 5% 10% 15%
Proved developed producing $5,238 $3,820 $3,051 $2,575
Proved developed non-producing 299 217 174 147
Proved undeveloped 1,305 612 312 152
Total Proved $6,842 $4,649 $3,537 $2,874
Probable 4,933 2,382 1,437 974
Total Proved Plus Probable Reserves (before tax) $11,775 $7,031 $4,974 $3,848

INFORMATION REGARDING RESERVES AND OPERATIONAL INFORMATION

Currency

All amounts in this news release are stated in Canadian dollars unless otherwise specified.

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

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, will be contained within our Annual Information Form for the year ended December 31, 2013 ("our AIF") which will be available in late February 2014 on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF will form part of our Form 40-F that will be filed with the U.S. Securities and Exchange Commission and will be available on EDGAR at www.sec.gov. Readers are also urged to review the Management's Discussion & Analysis and financial statements to be filed on SEDAR and EDGAR concurrently with our AIF for more complete disclosure on our operations.

F&D and FD&A Costs

F&D costs presented in this news release are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. 

FD&A costs presented in this news release are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding, development and acquisition costs related to its reserves additions for that year.

See "Non-GAAP Measures" below.

Other Metrics

Reserve life index is calculated by dividing the total applicable reserves quantity by the 2014  annual production as forecast in the reserves evaluations.

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. 

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 to bring reserves on production; the volumes and estimated net present value of Enerplus' oil and gas reserves and future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; the volume and product mix of Enerplus' oil and gas reserves and production; 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 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 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 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 Enerplus' Annual Information Form and Form 40-F described above).

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 ""F&D costs", "FD&A costs", "recycle ratio" and "operating netback" as measures of operating performance.  "Operating netback" is calculated as oil and gas sales revenues after deducting royalties, operating costs and transportation. A "recycle ratio" is calculated as F&D costs divided by operating netback.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "recycle ratio", "F&D costs" and "FD&A costs" 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 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

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