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