SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Report of Foreign Issuer
pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange
Act of 1934
FOR THE MONTH
OF FEBRUARY 2023
FORM 6-K
COMMISSION FILE NUMBER
1-15150
The Dome Tower
Suite
3000, 333 – 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200
US
Bank Tower
Suite 2200, 950 – 17th Street
Denver, Colorado
United States of
America 80202-2805
(720) 279-5500
Indicate by check mark whether
the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
EXHIBIT
INDEX
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
ENERPLUS CORPORATION
| BY: |
/s/ |
David A. McCoy |
|
| |
|
David A. McCoy |
|
| |
|
Vice President, General Counsel & Corporate Secretary |
|
| |
|
|
|
DATE: February 23, 2023
Exhibit 99.1
Enerplus Announces
2022 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. 23,
2023 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today reported year-end
2022 reserves under U.S. Standards and Canadian NI 51-101 Standards.
YEAR END 2022 RESERVES
SUMMARY
U.S. Standards -
after deduction of royalties ("net"), constant prices, U.S. dollars:
- Net total proved reserves were
322.3 MMBOE, a decrease of 5% year-over-year, with the reduction driven by the sale of substantially all of the Company's Canadian assets
in 2022. Excluding reserves changes due to the Canadian asset sales, net total proved reserves increased 2% year-over-year
- Enerplus added 40.8 MMBOE of net
proved reserves in 2022 (including technical revisions and economic factors), replacing 112% of its 2022 net production
- Net proved developed producing
("PDP") finding and development ("F&D") costs were $8.27 per BOE
- Net proved F&D costs were $16.43
per BOE, including future development costs ("FDC")
Canadian NI 51-101
Standards - before deduction of royalties ("gross"), forecast prices, U.S. dollars:
- Gross proved plus probable ("2P")
reserves were 601.1 MMBOE, a decrease of 2% year-over-year, with the reduction driven by the sale of substantially all of the Company's
Canadian assets in 2022. Excluding reserves changes due to the Canadian asset sales, gross 2P reserves increased 3% year-over-year
- Enerplus added 63.3 MMBOE of gross
2P reserves in 2022 (including technical revisions and economic factors), replacing 139% of its 2022 gross production
- Gross PDP F&D costs were $7.15
per BOE
- Gross 2P F&D costs were $17.82
per BOE, including FDC
"Enerplus' reserves
additions and production replacement at competitive costs highlight the sustainability of our business. The Company's deep resource base
in North Dakota continues to support a resilient long-term outlook," said Ian C. Dundas, President and CEO.
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, 2022. 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, 2022, see Enerplus' Annual Information Form
for the year ended December 31, 2022 (the "AIF") on Enerplus' SEDAR profile at www.sedar.com, and Enerplus' U.S. Form 40-F
for the year ended December 31, 2022 (the "Form 40-F") on EDGAR at www.sec.gov, each of which are anticipated to be filed on
February 23, 2023.
2022 Net Proved
Reserves Summary - U.S. Standards (Constant prices) (1)(2)
| |
Tight Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural Gas
Liquids
(Mbbls) |
Shale Gas
(MMcf) |
Total
(MBOE) |
| Net |
|
|
|
|
|
| Proved developed producing |
78,342 |
78,342 |
15,993 |
621,563 |
197,928 |
| Proved developed non-producing |
2,468 |
2,468 |
348 |
3,425 |
3,387 |
| Proved undeveloped |
68,144 |
68,144 |
10,758 |
252,480 |
120,982 |
| Total Proved |
148,953 |
148,953 |
27,100 |
877,468 |
322,298 |
| |
| 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 2022) 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. |
2022 Gross and Net
Proved plus Probable Reserves Summary - Canadian NI 51-101 Standards (Forecast prices) (1)(2)
| |
Tight Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural Gas
Liquids
(Mbbls) |
Shale Gas
(MMcf) |
Total
(MBOE) |
| Gross |
|
|
|
|
|
| Proved developed producing |
92,788 |
92,788 |
18,839 |
756,966 |
237,789 |
| Proved developed non-producing |
2,925 |
2,925 |
413 |
4,131 |
4,026 |
| Proved undeveloped |
84,560 |
84,560 |
13,340 |
313,106 |
150,085 |
| Total proved |
180,273 |
180,273 |
32,592 |
1,074,204 |
391,899 |
| Total probable |
136,863 |
136,863 |
23,743 |
291,705 |
209,224 |
| Gross Proved plus Probable |
317,136 |
317,136 |
56,335 |
1,365,908 |
601,123 |
| Net |
|
|
|
|
|
| Proved developed producing |
74,632 |
74,632 |
15,172 |
607,337 |
191,027 |
| Proved developed non-producing |
2,352 |
2,352 |
332 |
3,334 |
3,240 |
| Proved undeveloped |
67,699 |
67,699 |
10,676 |
252,747 |
120,500 |
| Total proved |
144,684 |
144,684 |
26,179 |
863,419 |
314,766 |
| Total probable |
109,661 |
109,661 |
19,036 |
237,802 |
168,331 |
| Net Proved plus Probable |
254,345 |
254,345 |
45,215 |
1,101,221 |
483,097 |
| |
| 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
2022 Net Proved
Reserves Reconciliation - U.S. Standards (Constant prices) (1)(2)(3)
| |
Light &
Medium
Oil
(Mbbls)(2) |
Heavy
Oil
(Mbbls)(2) |
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, 2021 |
5,213 |
13,464 |
144,697 |
163,374 |
27,561 |
15,117 |
873,268 |
888,385 |
339,000 |
Purchases of reserves in
place |
- |
- |
231 |
231 |
24 |
- |
143 |
143 |
278 |
| Sales of reserves in place |
(4,502) |
(12,531) |
(1,148) |
(18,181) |
(628) |
(12,955) |
(1,395) |
(14,349) |
(21,200) |
| Discoveries and extensions |
- |
- |
15,554 |
15,554 |
2,430 |
- |
122,762 |
122,762 |
38,444 |
Revisions of previous
estimates |
- |
- |
6,961 |
6,961 |
1,246 |
- |
(34,876) |
(34,876) |
2,394 |
| Improved recovery |
- |
- |
- |
- |
- |
- |
- |
- |
- |
| Production |
(712) |
(933) |
(17,342) |
(18,986) |
(3,534) |
(2,162) |
(82,433) |
(84,596) |
(36,619) |
Proved Reserves at
Dec. 31, 2022 |
- |
- |
148,953 |
148,953 |
27,100 |
- |
877,468 |
877,468 |
322,298 |
| |
| 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 2022) 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) |
Substantially all Canadian assets were sold during 2022. |
| (3) |
Tables may not add due to rounding. |
2022 Net Proved
Reserves Reconciliation - Canadian NI 51-101 Standards (Forecast prices) (1)(2)(3)
| |
Light &
Medium
Oil
(Mbbls)(2) |
Heavy
Oil
(Mbbls)(2) |
Tight
Oil
(Mbbls) |
Total
Crude
Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Conventional
Natural Gas
(MMcf) (2) |
Shale
Gas
(MMcf) |
Total
Natural
Gas
(MMcf) |
Total
(MBOE) |
Proved Reserves at
Dec. 31, 2021 |
5,173 |
13,255 |
143,365 |
161,793 |
27,236 |
14,648 |
861,939 |
876,586 |
335,127 |
| Acquisitions |
- |
- |
231 |
231 |
24 |
- |
143 |
143 |
278 |
| Dispositions |
(4,461) |
(12,322) |
(1,145) |
(17,929) |
(605) |
(12,485) |
(1,368) |
(13,853) |
(20,843) |
| Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
- |
- |
15,463 |
15,463 |
2,414 |
- |
54,910 |
54,910 |
27,029 |
| Economic factors |
- |
- |
3,998 |
3,998 |
809 |
- |
(356) |
(356) |
4,748 |
| Technical revisions |
- |
- |
114 |
114 |
(165) |
- |
30,584 |
30,584 |
5,046 |
| Production |
(712) |
(933) |
(17,342) |
(18,986) |
(3,534) |
(2,162) |
(82,433) |
(84,596) |
(36,619) |
Proved Reserves at
Dec. 31, 2022 |
- |
- |
144,684 |
144,684 |
26,179 |
- |
863,419 |
863,419 |
314,766 |
| |
| 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) |
Substantially all Canadian assets were sold during 2022. |
| (3) |
Tables may not add due to rounding. |
2022 Gross Proved
and Proved plus Probable Reserves Reconciliations - Canadian NI 51-101 Standards (Forecast prices) (1)(2)(3)
| |
Light &
Medium
Oil
(Mbbls)(2) |
Heavy Oil
(Mbbls)(2) |
Tight Oil
(Mbbls) |
Total
Crude Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Conventional
Natural Gas
(MMcf)(2) |
Shale
Gas
(MMcf) |
Total
Natural
Gas
(MMcf) |
Total
(MBOE) |
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 |
| Acquisitions |
- |
- |
290 |
290 |
31 |
- |
148 |
148 |
346 |
| Dispositions |
(5,267) |
(14,401) |
(1,432) |
(21,100) |
(728) |
(13,090) |
(1,655) |
(14,745) |
(24,286) |
| Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
- |
- |
19,235 |
19,235 |
3,002 |
- |
67,503 |
67,503 |
33,488 |
| Economic factors |
- |
- |
4,963 |
4,963 |
1,005 |
- |
5,924 |
5,924 |
6,956 |
| Technical revisions |
- |
- |
165 |
165 |
(220) |
- |
34,560 |
34,560 |
5,705 |
| Production |
(978) |
(1,211) |
(21,549) |
(23,737) |
(4,395) |
(2,106) |
(102,776) |
(104,882) |
(45,613) |
Proved Reserves at
Dec. 31, 2022 |
- |
- |
180,273 |
180,273 |
32,592 |
- |
1,074,204 |
1,074,204 |
391,899 |
| |
Light &
Medium
Oil
(Mbbls)(2) |
Heavy
Oil
(Mbbls)(2) |
Tight Oil
(Mbbls) |
Total
Crude
Oil (Mbbls) |
Natural
Gas Liquids
(Mbbls) |
Conventional
Natural Gas
(MMcf)(2) |
Shale
Gas
(MMcf) |
Total
Natural
Gas
(MMcf) |
Total
(MBOE) |
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 |
| Acquisitions |
- |
- |
363 |
363 |
38 |
- |
183 |
183 |
431 |
| Dispositions |
(7,184) |
(19,480) |
(1,782) |
(28,447) |
(996) |
(17,571) |
(2,156) |
(19,727) |
(32,731) |
| Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
- |
- |
43,451 |
43,451 |
7,018 |
- |
137,336 |
137,336 |
73,358 |
| Economic factors |
- |
- |
7,094 |
7,094 |
1,414 |
- |
8,203 |
8,203 |
9,875 |
| Technical revisions |
- |
- |
(9,786) |
(9,786) |
(2,965) |
- |
(42,808) |
(42,808) |
(19,886) |
| Production |
(978) |
(1,211) |
(21,549) |
(23,737) |
(4,395) |
(2,106) |
(102,776) |
(104,882) |
(45,613) |
Proved plus Probable
Reserves at Dec. 31, 2022 |
- |
- |
317,136 |
317,136 |
56,335 |
- |
1,365,908 |
1,365,908 |
601,123 |
| |
|
|
|
|
|
|
|
|
|
|
|
| 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) |
Substantially all Canadian assets were sold during 2022. |
| (3) |
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) |
| Year |
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 |
| 2023+ |
94.14 |
6.25 |
n/a |
|
|
2023 |
80.33 |
4.74 |
0.0 |
| |
|
|
|
|
|
2024 |
78.50 |
4.50 |
2.3 |
| |
|
|
|
|
|
2025 |
76.95 |
4.31 |
2.0 |
| |
|
|
|
|
|
2026 |
77.61 |
4.40 |
2.0 |
| |
|
|
|
|
|
2027 |
79.16 |
4.49 |
2.0 |
| |
|
|
|
|
|
2028 |
80.74 |
4.58 |
2.0 |
| |
|
|
|
|
|
2029 |
82.36 |
4.67 |
2.0 |
| |
|
|
|
|
|
2030 |
84.00 |
4.76 |
2.0 |
| |
|
|
|
|
|
2031 |
85.69 |
4.86 |
2.0 |
| |
|
|
|
|
|
2032 |
87.40 |
4.95 |
2.0 |
| |
|
|
|
|
|
2033 |
89.15 |
5.05 |
2.0 |
| |
|
|
|
|
|
2034 |
90.93 |
5.15 |
2.0 |
| |
|
|
|
|
|
2035 |
92.75 |
5.26 |
2.0 |
| |
|
|
|
|
|
2036 |
94.61 |
5.36 |
2.0 |
| |
|
|
|
|
|
2037 |
96.50 |
5.47 |
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 2022. 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, 2023, 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) |
|
|
|
| 2023 |
484 |
484 |
485 |
| 2024 |
344 |
347 |
347 |
| 2025 |
457 |
472 |
472 |
| 2026 |
236 |
248 |
316 |
| 2027 |
1 |
1 |
463 |
| 2028 |
0 |
0 |
379 |
| Remainder |
- |
0 |
574 |
| Total FDC Undiscounted |
1,523 |
1,553 |
3,038 |
| Total FDC Discounted at 10% |
1,297 |
1,320 |
2,207 |
| |
| 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' 2022 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 100% of the net present value (discounted at 10%, before tax, using January 1, 2023 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 all of the proved plus probable reserves associated with the Company's
properties located in North Dakota and Colorado. 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 Ltd. and Sproule Associates Limited, independent petroleum consultants, as of January
1, 2023 to prepare its report.
The Company has
also presented certain reserves information effective December 31, 2022 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.
F&D costs
presented in this news release are calculated (i) in the case of F&D costs for proved developed producing reserves, by dividing the
sum of the exploration and development costs incurred in the year, by the additions to proved developed producing reserves in the year,
(ii) 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 (iii) 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. F&D
costs are presented in U.S. dollars per net of 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, 2022 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
"crude oil" in this news release include light and medium crude oil, heavy oil and tight oil 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 2023
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 from those currently anticipated; changes in the demand for or supply of our
products, including global energy demand and including as a result of ongoing disruptions to global supply chains; 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' 2022 MD&A, AIF 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
View original content:
http://www.newswire.ca/en/releases/archive/February2023/23/c3236.html
%CIK: 0001126874
For further information: Investor
Contacts: Drew Mair, 403-298-1707, Krista Norlin, 403-298-4304
CO: Enerplus Corporation
CNW 17:00e 23-FEB-23
This regulatory filing also includes additional resources:
ex991.pdf
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