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 |
Total Oil |
Natural Gas |
Shale Gas (MMcf) |
Total |
|
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 |
Total Oil |
Natural Gas |
Shale Gas (MMcf) |
Total |
|
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 & |
Heavy (Mbbls)(2) |
Tight (Mbbls) |
Total (Mbbls) |
Natural |
Conventional |
Shale |
Total |
Total |
|
Proved Reserves at |
5,213 |
13,464 |
144,697 |
163,374 |
27,561 |
15,117 |
873,268 |
888,385 |
339,000 |
Purchases of reserves in |
– |
– |
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 |
– |
– |
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 |
– |
– |
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 & |
Heavy |
Tight |
Total |
Natural |
Conventional |
Shale |
Total |
Total |
|
Proved Reserves at |
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 |
– |
– |
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 |
– |
– |
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 & |
Heavy Oil |
Tight Oil |
Total |
Natural |
Conventional |
Shale |
Total |
Total |
|
Proved Reserves at |
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 |
– |
– |
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 |
– |
– |
180,273 |
180,273 |
32,592 |
– |
1,074,204 |
1,074,204 |
391,899 |
Light & |
Heavy |
Tight Oil |
Total |
Natural |
Conventional |
Shale |
Total |
Total |
|||
Proved plus Probable |
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 |
– |
– |
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 |
– |
– |
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 |
Forecast prices and cost escalation used under |
||||||||
Year |
WTI |
U.S. Henry Hub Gas Price |
Inflation Rate %/year |
WTI |
U.S. Henry Hub Gas Price |
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.