EX-99.1 2 ex991.htm NEWS RELEASE DATED FEBRUARY 24, 2022

Exhibit 99.1

 

 

 

Enerplus Announces 2021 Year End Reserves Results

Readers are advised to review the "Notice Regarding Information Contained in this News Release" at the conclusion of this news release for information regarding the presentation of the reserves information contained in this news release, including the definitions of, and differences between, "U.S. Standards" and "Canadian NI 51-101 Standards" used herein. 

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

CALGARY, AB, Feb. 24, 2022 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX: ERF) & (NYSE: ERF) today reported year-end 2021 reserves under U.S. Standards and Canadian NI 51-101 Standards.

2021 RESERVES HIGHLIGHTS

U.S. Standards - after deduction of royalties ("net"), constant prices, U.S. dollars:

  • Year end 2021 reserves summary:
    • Net proved developed producing reserves were 200 MMBOE, an increase of 77% year-over-year
    • Net total proved reserves were 339 MMBOE, an increase of 163% year-over-year
  • Enerplus added 244 MMBOE of net proved reserves in 2021 (including acquisitions, divestments, extensions, technical revisions and economic factors), replacing its 2021 production by over seven times
  • Net proved finding, development and acquisition ("FD&A") costs were $9.33 per BOE, including future development costs ("FDC")

Canadian NI 51-101 Standards - before deduction of royalties ("gross"), forecast prices, U.S. dollars:

  • Year end 2021 reserves summary:
    • Gross proved developed producing reserves were 243 MMBOE, an increase of 37% year-over-year
    • Gross total proved reserves were 415 MMBOE, an increase of 37% year-over-year
    • Gross proved plus probable ("2P") reserves were 616 MMBOE, an increase of 45% year-over-year
  • Enerplus added 233 MMBOE of gross 2P reserves in 2021 (including acquisitions, divestments, extensions, technical revisions and economic factors), replacing its 2021 production by over five times
  • Gross proved FD&A costs were $9.75 per BOE and gross 2P FD&A costs were $8.71 per BOE, including FDC

"Our strategic acquisitions, combined with the efficient execution of our development program drove substantial reserves growth in 2021 at attractive costs," said Ian C. Dundas, President and CEO. "This reserves growth has meaningfully extended our drilling inventory in North Dakota and further enhanced the sustainability of our long-term outlook."

YEAR-END RESERVES EVALUATIONS

Reserves Summary

The following information sets out Enerplus' net (prepared in accordance with U.S. Standards) and gross and net (prepared in accordance with Canadian NI 51-101 Standards) crude oil, natural gas liquids ("NGLs") and natural gas reserves volumes as at December 31, 2021. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit associated with a property. For additional information regarding Enerplus' crude oil, NGLs and natural gas reserves as at December 31, 2021, see Enerplus' Annual Information Form for the year ended December 31, 2021 (the "AIF") on Enerplus' SEDAR profile at www.sedar.com, and Enerplus' U.S. Form 40-F for the year ended December 31, 2021 (the "Form 40-F") on EDGAR at www.sec.gov, each of which are anticipated to be filed on February 24, 2022. 

2021 Net Proved Reserves Summary - U.S. Standards (Constant prices) (1)(2)

  Light &
Medium
Oil
(Mbbls)		 Heavy Oil
(Mbbls)		 Tight Oil
(Mbbls)		 Total Oil
(Mbbls)		 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)

Shale Gas

(MMcf)

 Total
(MBOE)
Net                
Proved developed producing 4,656 12,171 72,859 89,686 15,281 15,067 555,906 200,130
Proved developed non-producing - - 1,524 1,524 262 - 4,665 2,564
Proved undeveloped 557 1,293 70,314 72,164 12,018 50 312,696 136,306
Total Proved 5,213 13,464 144,697 163,374 27,561 15,117 873,268 339,000

 

Notes:  
(1) Volumes are calculated in accordance with U.S. Standards, using net reserves (being the Company's working interest share after deduction of royalty interests plus the Company's royalty interests) and constant prices (being the unweighted arithmetic average of the first-day-of the-month price for the applicable product for each of the twelve months in 2021) and costs.  For additional information regarding U.S. Standards, see "Notice Regarding Information Contained in this News Release – Presentation of Reserves Information" in this news release.
(2) Tables may not add due to rounding.

 

2021 Gross and Net Proved plus Probable Reserves Summary - Canadian NI 51-101 Standards (Forecast prices) (1)(2)

  Light &
Medium Oil
(Mbbls)		 Heavy Oil
(Mbbls)		 Tight Oil
(Mbbls)		 Total Oil
(Mbbls)		 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)

Shale Gas

(MMcf)

 Total
(MBOE)
Gross                
Proved developed producing 5,585 14,099 89,263 108,947 18,640 15,140 678,681 243,223
Proved developed non-producing - - 1,863 1,863 320 - 5,730 3,138
Proved undeveloped 660 1,513 87,475 89,648 14,937 56 386,089 168,943
Total proved 6,245 15,612 178,600 200,457 33,897 15,196 1,070,500 415,304
Total probable 1,917 5,079 120,746 127,742 22,324 4,481 297,427 200,384
Gross Proved plus Probable 8,162 20,691 299,346 328,199 56,221 19,677 1,367,927 615,688
Net                
Proved developed producing 4,616 11,970 71,850 88,437 15,025 14,598 547,332 197,117
Proved developed non-producing - - 1,503 1,503 259 - 4,642 2,536
Proved undeveloped 557 1,285 70,011 71,853 11,953 50 309,964 135,474
Total proved 5,173 13,255 143,365 161,793 27,236 14,648 861,939 335,127
Total probable 1,551 4,210 96,717 102,478 17,902 4,329 244,049 161,776
Net Proved plus Probable 6,724 17,465 240,082 264,271 45,139 18,977 1,105,988 496,904

 

Notes:  
(1) Volumes are calculated in accordance with Canadian NI 51-101 Standards, using gross reserves (being the Company's working interest share before deduction of royalty interests and without including any of the Company's royalty interests) and net reserves (being the Company's working interest share after deduction of royalty interests plus the Company's royalty interests), forecast prices and escalating costs. For additional information regarding the forecast prices used and Canadian NI 51-101 Standards, see "Price Assumptions Used Under U.S. Standards and Canadian NI 51-101 Standards" and "Notice Regarding Information Contained in this News Release – Presentation of Reserves Information" in this news release.
(2) Tables may not add due to rounding.

 

Reserves Reconciliation

2021 Net Proved Reserves Reconciliation - U.S. Standards (Constant prices) (1)(2)

  Light &
Medium
Oil
(Mbbls)

Heavy
Oil

(Mbbls)

Tight
Oil

(Mbbls)

Total
Crude
Oil

(Mbbls)

 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)		 Shale
Gas
(MMcf)		 Total
Natural
Gas
(MMcf)		 Total
(MBOE)
Proved Reserves at
Dec. 31, 2020		 4,964 10,642 37,740 53,345 5,311 14,052 407,466 421,517 128,910
Purchases of reserves in place - - 50,713 50,713 9,755 - 59,185 59,185 70,332
Sales of reserves in place (10) - (3,429) (3,438) (98) (1,419) (7,933) (9,352) (5,095)
Discoveries and extensions 7 1,293 64,546 65,845 11,057 503 336,511 337,014 133,071
Revisions of previous estimates 1,067 2,734 10,816 14,617 4,392 4,835 153,771 158,606 45,443
Improved recovery - - - - - - - - -
Production (814) (1,205) (15,688) (17,708) (2,856) (2,853) (75,733) (78,586) (33,661)
Proved Reserves at
Dec. 31, 2021		 5,213 13,464 144,697 163,374 27,561 15,117 873,268 888,385 339,000
                   

 

Notes:  
(1) Volumes are calculated in accordance with U.S. Standards, using net reserves (being the Company's working interest share after deduction of royalty interests plus the Company's royalty interests) and constant prices (being the unweighted arithmetic average of the first-day-of the-month price for the applicable product for each of the twelve months in 2021) and costs. For additional information regarding U.S. Standards, see "Notice Regarding Information Contained in this News Release – Presentation of Reserves Information" at the conclusion of this news release.
(2) Tables may not add due to rounding.

2021 Net Proved Reserves Reconciliation - Canadian NI 51-101 Standards (Forecast prices) (1)(2)

  Light &
Medium
Oil
(Mbbls)		 Heavy
Oil
(Mbbls)		 Tight
Oil
(Mbbls)		 Total
Crude
Oil
(Mbbls)		 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)		 Shale
Gas
(MMcf)		 Total
Natural
Gas
(MMcf)		 Total
(MBOE)
Proved Reserves at
Dec. 31, 2020		 5,534 14,663 85,281 105,477 12,048 18,008 743,705 761,712 244,478
Acquisitions - - 50,231 50,231 9,658 - 58,618 58,618 69,658
Dispositions (19) - (4,121) (4,141) (213) (2,851) (9,417) (12,268) (6,399)
Discoveries - - - - - - - - -
Extensions & improved recovery 6 - 26,537 26,543 4,424 459 98,091 98,550 47,393
Economic factors 179 259 3,266 3,705 910 1,851 4,816 6,667 5,726
Technical revisions 288 (462) (2,141) (2,315) 3,265 35 41,858 41,893 7,933
Production (814) (1,205) (15,688) (17,708) (2,856) (2,853) (75,733) (78,586) (33,661)
Proved Reserves at
Dec. 31, 2021		 5,173 13,255 143,365 161,793 27,236 14,648 861,939 876,586 335,127

 

Notes:  
(1) Volumes are calculated in accordance with Canadian NI 51-101 Standards, using net reserves (being the Company's working interest share after deduction of royalty interests), forecast prices and escalating costs.  For additional information regarding the forecast prices used and Canadian NI 51-101 Standards, see "Notice Regarding Information Contained in this News Release – Presentation of Reserves Information" at the conclusion of this news release.
(2) Tables may not add due to rounding.

2021 Gross Proved and Proved plus Probable Reserves Reconciliations - Canadian NI 51-101 Standards (Forecast prices) (1)(2)

  Light &
Medium
Oil
(Mbbls)		 Heavy
Oil
(Mbbls)		 Tight
Oil
(Mbbls)		 Total
Crude
Oil
(Mbbls)		 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)		 Shale
Gas
(MMcf)		 Total
Natural
Gas
(MMcf)		 Total
(MBOE)
Proved Reserves at
Dec. 31, 2020		 6,637 16,946 106,186 129,769 14,900 17,353 929,546 946,899 302,485
Acquisitions - - 62,317 62,317 11,948 - 67,418 67,418 85,502
Dispositions (20) - (5,152) (5,172) (154) (1,520) (11,755) (13,275) (7,539)
Discoveries - - - - - - - - -
Extensions & improved recovery 8 - 33,074 33,082 5,501 189 122,366 122,554 59,008
Economic factors 293 549 4,086 4,927 1,083 1,089 12,403 13,491 8,259
Technical revisions 437 (387) (2,501) (2,452) 4,162 900 44,917 45,817 9,347
Production (1,110) (1,495) (19,409) (22,014) (3,542) (2,815) (94,395) (97,209) (41,757)
Proved Reserves at
Dec. 31, 2021		 6,245 15,612 178,600 200,457 33,897 15,196 1,070,500 1,085,696 415,304
                   

 

 

 

Light &
Medium
Oil
(Mbbls)

 Heavy
Oil
(Mbbls)		 Tight
Oil
(Mbbls)		 Total
Crude
Oil
(Mbbls)		 Natural
Gas
Liquids
(Mbbls)		 Conventional
Natural Gas
(MMcf)		 Shale
Gas
(MMcf)		 Total
Natural
Gas
(MMcf)		 Total
(MBOE)
Proved plus Probable Reserves at Dec. 31, 2020

 

9,020

 22,254 170,127 201,402 23,501 23,164 1,173,934 1,197,098 424,419
Acquisitions - - 116,119 116,119 21,854 - 118,233 118,233 157,678
Dispositions (22) - (6,592) (6,614) (207) (2,018) (14,887) (16,905) (9,638)
Discoveries - - - - - - - - -
Extensions & improved recovery 9 - 46,777 46,786 7,807 241 162,123 162,364 81,653
Economic factors 316 684 5,247 6,246 1,359 1,277 15,599 16,875 10,418
Technical revisions (51) (753) (12,922) (13,725) 5,449 (172) 7,320 7,148 (7,085)
Production (1,110) (1,495) (19,409) (22,014) (3,542) (2,815) (94,395) (97,209) (41,757)
Proved plus Probable Reserves at Dec. 31, 2021 8,162 20,691 299,346 328,199 56,221 19,677 1,367,927 1,387,604 615,688
                   

 

Notes:  
(1) Volumes are calculated in accordance with Canadian NI 51-101 Standards, using gross reserves (being the Company's working interest share before deduction of royalty interests), forecast prices and escalating costs. For additional information regarding the forecast prices used and Canadian NI 51-101 Standards, see "Notice Regarding Information Contained in this News Release – Presentation of Reserves Information" at the conclusion of this news release.
(2) Tables may not add due to rounding.

Price Assumptions Used Under U.S. Standards and Canadian NI 51-101 Standards

Constant prices used under
U.S. Standards(2)		     Forecast prices and cost escalation used under
Canadian NI 51-101 Standards(3)
  WTI
Crude Oil
US$/bbl		 U.S. Henry Hub
Gas Price
US$/MMBtu

Inflation Rate

%/year

       WTI
Crude Oil
US$/bbl		 U.S. Henry Hub
Gas Price
US$/MMBtu

Inflation Rate

%/year

2022+ $66.55 $3.64 N/A     2022 72.83 3.85 0.0
            2023 68.78 3.44 2.3
            2024 66.76 3.17 2.0
            2025 68.09 3.24 2.0
            2026 69.45 3.30 2.0
            2027 70.84 3.37 2.0
            2028 72.26 3.44 2.0
            2029 73.70 3.50 2.0
            2030 75.18 3.58 2.0
            2031 76.68 3.65 2.0
            2032 78.21 3.72 2.0
            2033 79.78 3.79 2.0
            2034 81.37 3.87 2.0
            2035 83.00 3.95 2.0
            2036 84.66 4.03 2.0
            Thereafter (1) (1) 2.0

 

Notes:  
(1) Escalation is approximately 2% per year thereafter.
(2) Represents the unweighted arithmetic average of the first-day-of the-month price for that product for each of the twelve months in 2021. Under the U.S. Standards costs are not inflated.
(3) Represents the average commodity price forecasts and inflation rates of McDaniel & Associates Consultants Ltd, GLJ Ltd. and Sproule Associates Limited as of January 1, 2022, and assume no legislative or regulatory amendments. 

Future Development Costs

Changes in forecast FDC occur annually as a result of development activities, acquisition and divestment 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 FDC generally reflect the total finding and development costs related to reserves additions for that year.

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

  U.S. Standards(1)(2) Canadian NI 51-101 Standards(1)(2)
Future Development Costs

Proved

Reserves

Proved

Reserves

Proved Plus

Probable Reserves

(US$ millions)      
2022 332 332 343
2023 359 363 362
2024 352 361 364
2025 312 327 429
2026 8 9 388
2027 3 3 430
Remainder 2 2 128
Total FDC Undiscounted 1,369 1,397 2,444
Total FDC Discounted at 10% 1,152 1,173 1,830

 

Note:  
(1) FDC under U.S. Standards are not inflated.  FDC under Canadian NI 51-101 Standards are inflated as per the price assumption table in the section above.
(2) Tables may not add due to rounding.

Electronic copies of the AIF and Form 40-F, along with Enerplus' 2021 MD&A and Financial Statements and other public information including investor presentations, are available on the Company's 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.

About Enerplus

Enerplus is an independent North American oil and gas exploration and production company focused on creating long-term value for its shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations. For more information, visit the Company's website at www.enerplus.com.

NOTICE REGARDING INFORMATION CONTAINED IN THIS NEWS RELEASE

Barrels of Oil Equivalent

This news release also contains references to "BOE" (barrels of oil equivalent), "MBOE" (one thousand barrels of oil equivalent), and "MMBOE" (one million 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.  BOE, MBOE and MMBOE 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.

Presentation of Reserves and Other Oil and Gas Information

All of the Company's reserves have been evaluated in accordance with Canadian reserve evaluation standards under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("Canadian NI 51-101 Standards"). Independent reserves evaluations have been conducted on properties comprising approximately 98% of the net present value (discounted at 10%, before tax, using January 1, 2022 forecast prices and costs) of the Company's total proved plus probable reserves.  McDaniel & Associates Consultants Ltd. ("McDaniel"), an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 71% of the net present value (discounted at 10%, before tax, using the average commodity price forecasts and inflation rates of McDaniel, GLJ Ltd. ("GLJ") and Sproule Associates Limited ("Sproule") as of January 1, 2022) of the Company's proved plus probable reserves located in Canada and all of the reserves associated with the Company's properties located in North Dakota and Colorado. The Company has evaluated the remaining 29% of the net present value of its Canadian properties using similar evaluation parameters, including the same forecast price and inflation rate assumptions utilized by McDaniel. McDaniel has reviewed the Company's internal evaluation of these properties. Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum consultants based in Dallas, Texas, has evaluated all of the Company's reserves associated with the Company's properties in Pennsylvania in accordance with Canadian NI 51-101 Standards. For consistency in the Company's reserves reporting, NSAI also used the average commodity price forecasts and inflation rates of McDaniel, GLJ and Sproule as of January 1, 2022 to prepare its report.

The Company has also presented certain reserves information effective December 31, 2021 in accordance with the provisions of the Financial Accounting Standards Board's ASC Topic 932 Extractive Activities – Oil and Gas ("ASC 932"), which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission ("SEC Rules"), but does not necessarily include all of the disclosure required by the SEC disclosure standards set forth in Subpart 1200 of Regulation S-K (collectively, the "U.S. Standards"). Concurrent to the evaluation of the Company's Canadian NI 51-101 Standards reserves, McDaniel and NSAI prepared and reviewed estimates of the Company's reserves under the U.S. Standards. The practice of preparing production and reserves data under Canadian NI 51-101 Standards differs from the U.S. Standards.  The primary differences between the two reporting requirements include:

  • the Canadian NI 51-101 Standards require disclosure of proved and probable reserves, while the U.S. Standards require disclosure of only proved reserves;
  • the Canadian NI 51-101 Standards require the use of forecast prices in the estimation of reserves, while the U.S. Standards require the use of 12-month average trailing historical prices, which are held constant;
  • the Canadian NI 51-101 Standards require disclosure of reserves on a gross (before royalties) and net (after royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;
  • the Canadian NI 51-101 Standards require disclosure of production on a gross (before royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;
  • the Canadian NI 51-101 Standards require that reserves and other data be reported on a more granular product type basis than required by the U.S. Standards;
  • the Canadian NI 51-101 Standards require that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves; and
  • The SEC prohibits disclosure of oil and gas resources in SEC filings, including contingent resources, whereas Canadian securities regulatory authorities allow disclosure of oil and gas resources. Resources are different than, and should not be construed as, reserves.

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. FD&A costs are presented in U.S. dollars per net or gross BOE as specified.

Complete disclosure of our oil and gas reserves and other oil and gas information presented in accordance with Canadian NI 51-101 Standards , as well as supplemental information presented in accordance with U.S. Standards, is contained within 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 audited financial statements for the year ended December 31, 2021 filed on SEDAR and as part of our Form 40-F filed on EDGAR concurrently with this news release for more complete disclosure on our operations.

All references to "liquids" in this news release include light and medium crude oil, heavy oil and tight oil (all together referred to as "crude oil") and NGLs on a combined basis. All references to "natural gas" in this news release include conventional natural gas and shale gas on a combined basis.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "anticipate", "estimate", "believes" 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: the quantity of the Company's oil and gas reserves; forecast oil and natural gas prices in 2022 and in the future; and estimated future FDC. Additionally, statements relating to "reserves" are also deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity prices, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; and the availability of third party services. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this 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: decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; inaccurate estimation of our oil and gas reserve and contingent resource volumes; increased costs; reliance on industry partners and third party service providers; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies described under "Risk Factors and Risk Management" in Enerplus' 2021 MD&A and in our other public filings).

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

SOURCE Enerplus Corporation

 

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For further information: Investor Contacts: Drew Mair, 403-298-1707; Krista Norlin, 403-298-4304

CO: Enerplus Corporation

CNW 17:00e 24-FEB-22