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Returns & Value Focused

At Enerplus, we're focused on creating long-term value for our shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations.

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News Releases


Enerplus Announces 2021 Year End Reserves Results

February 24, 2022

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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