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⁾

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

Reserves Reconciliation

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

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

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

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

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:

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 [email protected].

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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