EXHIBIT 99.12

Supplemental Information About Crude Oil and Natural Gas Producing Activities (unaudited)

The following disclosures, including proved reserves, future net cash flows, and costs incurred attributable to Enerplus' crude oil and natural gas operations have been prepared in accordance with the provisions of the Financial Accounting Standards Board's ASC Topic 932 "Extractive Activities – Oil and Gas” (“ASC 932”). All amounts pertaining to Enerplus’ audited consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to "$" and "CDN$" are to Canadian dollars. References to "US$" are to U.S. dollars.

On January 25, 2021, Enerplus entered into an agreement (the “Purchase Agreement”) to acquire the equity interests of Bruin E&P HoldCo, LLC (“Bruin”), a pure play Williston Basin private company, for total cash consideration of US$465 million, subject to certain adjustments (the “Bruin Acquisition”). Closing of the Bruin Acquisition is expected to occur early in March 2021 and is subject to customary closing conditions. The information presented in this document does not give effect to the Bruin Acquisition. For information on the Bruin Acquisition and Bruin’s reserve data and certain other crude oil and gas information as at December 31, 2020 refer to the material change report dated January 29, 2021 in connection with the Bruin Acquisition and available under the Enerplus’ SEDAR profile at www.sedar.com and on the Enerplus’ EDGAR profile under Form 6-K at www.sec.gov.

A. ESTIMATED PROVED CRUDE OIL AND NATURAL GAS RESERVE QUANTITIES

Users of this information should be aware that the process of estimating quantities of "proved" crude oil, natural gas and natural gas liquids reserves is very complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Future fluctuations in prices and costs, production rates, or changes in political or regulatory environments could cause Enerplus’ reserves to be materially different from that presented.

ASC 932 requires the use of a 12 month average price to estimate proved reserves calculated as the unweighted arithmetic average of first-day-of-the-month prices within the 12 month period prior to the end of the reporting period (the “Constant Price”). Proved reserves and production volumes are presented net of royalties in accordance with U.S. practice.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under ASC 932. Proved crude oil and gas reserves are those quantities of crude oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulation. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

The proved reserves disclosed herein are determined according to the definition of "proved reserves" under NI 51-101 which may differ from the definition provided in SEC rules, however Enerplus does not believe differences are material to Enerplus’ proved reserves. The reserves data presented in this Exhibit are a summary of evaluations, and as a result the tables may contain slightly different quantities than the evaluations themselves due to rounding. Additionally, the columns and rows in the tables may not add due to rounding. See "Presentation of Enerplus' Crude Oil and Gas Reserves, Contingent Resources, and Production Information" in Enerplus' Annual Information Form.

Subsequent to December 31, 2020, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved reserves as of that date.

Enerplus’ proved crude oil, natural gas and natural gas liquids (NGLs) reserves are located in the United States, primarily in the states of Colorado, Montana, North Dakota, and Pennsylvania, as well as western Canada, primarily in Alberta and Saskatchewan. Enerplus’ net proved reserves summarized in the following table represent Enerplus’ lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties as of December 31, 2020.

	Canada		United States		Total		Total
	Crude Oil	Natural	Crude Oil	Natural	Crude Oil	Natural	All
	and NGLs	Gas	and NGLs	Gas	and NGLs	Gas	Products
	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mboe)
Reserves at December 31, 2017	27,383	36,551	74,270	472,459	101,653	509,010	186,488
Purchases of reserves in place	—	—	128	73	128	73	140
Sales of reserves in place	(40)	(4,252)	(136)	(64)	(176)	(4,316)	(895)
Discoveries and extensions	965	1,180	24,791	64,451	25,756	65,631	36,695
Revisions of previous estimates	269	930	4,020	189,251	4,289	190,182	35,986
Improved recovery	541	17	—	—	541	17	544
Production	(2,988)	(9,083)	(11,577)	(67,901)	(14,565)	(76,984)	(27,396)
Proved Developed and Undeveloped
Reserves at December 31, 2018	26,130	25,343	91,496	658,270	117,626	683,613	231,562
Purchases of reserves in place	—	—	—	—	—	—	—
Sales of reserves in place	(814)	(190)	—	—	(814)	(190)	(845)
Discoveries and extensions	375	936	22,689	191,506	23,064	192,442	55,138
Revisions of previous estimates	695	(450)	(8,193)	(55,505)	(7,498)	(55,956)	(16,823)
Improved recovery	—	—	—	—	—	—	—
Production	(2,707)	(7,882)	(13,216)	(74,455)	(15,923)	(82,337)	(29,646)
Proved Developed and Undeveloped
Reserves at December 31, 2019	23,680	17,756	92,777	719,816	116,456	737,572	239,385
Purchases of reserves in place	—	—	—	—	—	—	—
Sales of reserves in place	—	—	—	—	—	—	—
Discoveries and extensions	—	—	1,931	16,613	1,931	16,613	4,700
Revisions of previous estimates	(5,115)	943	(39,543)	(263,700)	(44,658)	(262,757)	(88,451)
Improved recovery	—	—	—	—	—	—	—
Production	(2,382)	(4,239)	(12,690)	(65,672)	(15,072)	(69,911)	(26,724)
Proved Developed and Undeveloped
Reserves at December 31, 2020	16,182	14,461	42,475	407,056	58,657	421,517	128,910
Proved Developed Reserves
December 31, 2017	24,883	35,347	39,655	416,313	64,537	451,660	139,814
December 31, 2018	23,065	25,271	50,645	458,649	73,710	483,920	154,363
December 31, 2019	20,480	17,684	49,852	475,155	70,332	492,839	152,472
December 31, 2020	15,421	14,447	37,966	360,446	53,387	374,893	115,869
Proved Undeveloped Reserves
December 31, 2017	2,501	1,204	34,615	56,146	37,116	57,350	46,674
December 31, 2018	3,065	72	40,852	199,621	43,916	199,693	77,198
December 31, 2019	3,200	73	42,925	244,661	46,124	244,733	86,913
December 31, 2020	761	13	4,508	46,610	5,270	46,624	13,040

Purchases of reserves in place

In 2018, the Company acquired minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also divested an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

In 2019, the Company acquired no additional working interest reserve volumes through purchases.

In 2020, the Company acquired no additional working interest reserve volumes through purchases.

Sales of reserves in place

In 2018, the company sold working interests in developed and undeveloped land in one crude oil property and eight natural gas properties located in Alberta.

In 2018, the Company also divested minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also acquired an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

In 2019, the company sold working interests in developed and undeveloped land in three crude oil properties located in Saskatchewan and 11 natural gas properties located in Alberta.

In 2020, the Company did not sell working interests of any of its reserves in place.

Discoveries and extensions

The Company added 24,791 Mbbl, 22,026 Mbbl and 1,655 Mbbl of net proved crude oil and NGLs reserves on its Bakken/Three Forks properties in 2018, 2019 and 2020, respectively. The Company added 52,880 MMcf, 179,834 MMcf and 15,299 MMcf of net proved natural gas reserves in 2018, 2019 and 2020, respectively, on its Marcellus natural gas property. These discoveries and extensions were all primarily due to successful well development.

In 2018, Canadian discoveries and extensions accounted for an increase of 965 Mbbl of net proved crude oil and NGLs reserves and 1,180 MMcf of net proved natural gas reserves in the Med Hat Glauconitic C polymer flood and Giltedge crude oil properties located in Alberta, and the Saskatchewan Freda Lake crude oil property.

In 2019, Canadian discoveries and extensions accounted for an increase of 282 Mbbl of net proved crude oil reserves in the Saskatchewan Freda Lake crude oil property, and 59 Mbbl of net proved crude oil reserves and 936 MMcf of net proved natural gas reserves in the Ferrier, Fir and Willesden Green North properties located in Alberta.

In 2020, there were no discoveries or extensions in Canadian crude oil or natural gas properties.

Revisions of previous estimates

In 2018, positive revisions to United States crude oil reserves were primarily due to an increase in the Constant crude oil price compared to 2017. Positive revisions to United States natural gas reserves were primarily due to improved production performance and also an increase in the Constant gas price forecast compared to 2017.

In 2019, negative revisions to United States crude oil reserves were primarily due to a decrease in the Constant crude oil price forecast, as well as economic truncation due to an increase in operating expenses. Negative revisions to United States natural gas were primarily due to revised development plans and deletion of proved undeveloped wells in the Marcellus natural gas property.

In 2020, negative revisions to United States crude oil reserves were primarily due to a decrease in the Constant crude oil price forecast, which caused economic truncation of producing volumes and the removal of undeveloped locations that were no longer economic. Negative revisions to United States natural gas were also primarily due to a decrease in the Constant gas price forecast, which caused economic truncations of producing volumes and the removal of no longer economic undeveloped locations.

In 2018, the positive revisions to Canadian crude oil reserves were primarily due to an increase in the Constant crude oil price forecast compared to 2017. Positive revisions to Canadian natural gas reserves were primarily due to improved production performance.

In 2019, positive revisions to Canadian crude oil reserves were primarily due to improved production performance. Negative revisions to Canadian natural gas reserves were primarily due to a decrease in the Constant gas price forecast compared to 2018.

In 2020, negative revisions to Canadian crude oil reserves were due to negative revisions to previous estimates in the Medicine Hat Glauconitic C polymer flood and a decrease in the Constant crude oil price forecast compared to 2019. Conversely, an increase in the Constant price forecast for Canadian gas compared to 2019 resulted in positive revisions to Canadian natural gas reserves.

Improved Recovery

In 2018 in the Ante Creek North waterflood property located in Alberta, there was an improved recovery revision of 541 Mbbl of net proved crude oil and NGLs reserves and 17 MMcf of net proved natural gas reserves.

B. CAPITALIZED COSTS RELATED TO CRUDE OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation and depletion, including impairments, relating to Enerplus’ crude oil and gas exploration, development and producing activities are as follows:

	2020		2019		2018
	(in $ thousands)
Capitalized costs(1)	$	15,227,076	$	15,088,724	$	14,773,082
Less accumulated depletion, depreciation and impairment		(14,651,517)		(13,541,362)		(13,479,141)
Net capitalized costs	$	575,559	$	1,547,362	$	1,293,941

Note:

(1) Includes capitalized costs of proved and unproved properties.

C. COSTS INCURRED IN CRUDE OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in connection with crude oil and gas acquisition, exploration and development activities are presented in the table below. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire crude oil and gas properties, including an allocation of purchase price on business combinations that result in property acquisitions. Development costs include asset retirement costs capitalized and the costs of drilling and equipping development wells and facilities to extract, gather and store crude oil and gas, along with an allocation of overhead. Exploration costs include costs related to the discovery and the drilling and completion of exploratory wells in new crude oil and natural gas reservoirs.

	For the Year Ended December 31, 2020
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	303	$	—	$	303
Unproved		2,340		7,478		9,818
Exploration costs		132		645		777
Development costs		25,527		269,789		295,316
	$	28,302	$	277,912	$	306,214

	For the Year Ended December 31, 2019
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	2,765	$	1,230	$	3,995
Unproved		3,244		17,167		20,411
Exploration costs		359		616		975
Development costs		56,729		587,800		644,529
	$	63,097	$	606,813	$	669,910

	For the Year Ended December 31, 2018
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	—	$	6,055	$	6,055
Unproved		3,888		15,624		19,512
Exploration costs		641		979		1,620
Development costs		61,632		547,667		609,299
	$	66,161	$	570,325	$	636,486

D. RESULTS OF OPERATIONS FOR CRUDE OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to Enerplus' crude oil and gas producing activities for the years ended December 31, 2020, 2019 and 2018:

	For the Year Ended December 31, 2020
	Canada		United States		Total
	(in $ thousands)
Revenue
Sales(1)	$	96,499	$	640,706	$	737,205
Deduct(2)
Production costs(3)		65,650		380,211		445,861
Depletion, depreciation and accretion (“DD&A”)		46,783		246,373		293,156
Impairment		134,349		1,063,194		1,197,543
Current and deferred income tax provision (recovery)		(24,584)		(236,170)		(260,754)
Results of operations for crude oil and gas producing activities	$	(125,699)	$	(812,902)	$	(938,601)
DD&A per net BOE unit of production	$	15.15		10.42		10.97

	For the Year Ended December 31, 2019
	Canada		United States		Total
	(in $ thousands)
Revenue
Sales(1)
Deduct(2)	$	177,299	$	1,077,507	$	1,254,806
Production costs(3)
Depletion, depreciation and accretion (“DD&A”)		84,781		433,997		518,778
Impairment		59,936		296,894		356,830
Current and deferred income tax provision (recovery)		451,121		—		451,121
Results of operations for crude oil and gas producing activities		(2,887)		50,748		47,861
DD&A per net BOE unit of production	$	(415,652)	$	295,868	$	(119,784)
	$	14.91	$	11.59	$	12.04

	For the Year Ended December 31, 2018
	Canada		United States		Total
	(in $ thousands)
Revenue
Sales(1)	$	198,263	$	1,094,473	$	1,292,736
Deduct(2)
Production costs(3)		89,584		359,426		449,010
Depletion, depreciation and accretion (“DD&A”)		58,333		245,941		304,274
Current and deferred income tax provision (recovery)		3,515		99,696		103,211
Results of operations for crude oil and gas producing activities	$	46,831	$	389,410	$	436,241
DD&A per net BOE unit of production	$	12.96	$	10.74	$	11.11

Notes:

(1) Sales are presented net of royalties

(2) The costs deducted in this schedule exclude corporate overhead, interest expense and other costs which are not directly related to crude oil and gas producing activities.

(3) Production costs include operating costs, transportation costs and production taxes.

E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED CRUDE OIL AND NATURAL GAS RESERVE QUANTITIES

The following tables set forth the standardized measure of discounted future net cash flows from projected production of Enerplus’ crude oil and natural gas reserves:

	As at December 31, 2020
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	573		1,849		2,422
Future production costs		345		1,118		1,463
Future development and asset retirement costs		267		233		501
Future income tax expenses		—		—		—
Future net cash flows	$	(39)		497		458
Deduction: 10% annual discount factor		(92)		56		(37)
Standardized measure of discounted future net cash flows	$	53		442		495

	As at December 31, 2019
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	1,283		6,395		7,678
Future production costs		591		2,210		2,801
Future development and asset retirement costs		321		1,365		1,685
Future income tax expenses		—		254		254
Future net cash flows	$	371		2,566		2,937
Deduction: 10% annual discount factor		76		893		968
Standardized measure of discounted future net cash flows	$	296		1,673		1,969

	As at December 31, 2018
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	1,350		7,090		8,440
Future production costs		643		2,109		2,752
Future development and asset retirement costs		143		1,316		1,459
Future income tax expenses		—		508		508
Future net cash flows	$	564	$	3,157	$	3,721
Deduction: 10% annual discount factor		206		1,177		1,383
Standardized measure of discounted future net cash flows	$	358	$	1,980	$	2,338

F. CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED CRUDE OIL AND NATURAL GAS RESERVES

	2020		2019		2018
	(in $ millions)
Beginning of year	$	1,969	$	2,338	$	1,540
Sales of crude oil and natural gas produced, net of production costs		(291)		(736)		(844)
Net changes in sales prices and production costs		(2,707)		(996)		1,195
Changes in previously estimated development costs incurred during the period		291		618		594
Changes in estimated future development costs		739		(506)		(892)
Extension, discoveries and improved recovery, net of related costs		40		889		978
Purchase of reserves in place		—		—		2
Sales of reserves in place		—		(7)		(2)
Net change resulting from revisions in previous quantity estimates		148		(97)		(114)
Accretion of discount		182		232		143
Net change in income taxes		110		145		(247)
Other significant factors (Exchange rate)		14		89		(15)
End of year	$	495	$	1,969	$	2,338