Enerplus (ERF) 40-F 2018 FY Annual report (Canada)

EXHIBIT 99.12

Supplemental Information About Oil and 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 Accounting Standards codification (ASC) Topic 932 "Extractive Activities – Oil and Gas”. The standard 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. Proved reserves and production volumes are presented net of royalties in accordance with U.S. protocol.

A. PROVED OIL AND NATURAL GAS RESERVE QUANTITIES

Users of this information should be aware that the process of estimating quantities of "proved developed" and "proved undeveloped" crude oil, natural gas and natural gas liquids is very complex, requiring significant subjective decisions in the evaluation of all 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 the Corporation's reserves to be materially different from that presented.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under the ASC. Proved oil and gas reserves are those quantities of 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 the differences are not 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 numbers 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' Oil and Gas Reserves, Contingent Resources, and Production Information" in Enerplus' Annual Information Form. All cost information in this section is stated in Canadian dollars and is calculated in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").

Subsequent to December 31, 2018, 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’ December 31, 2018 proved crude oil, natural gas and natural gas liquids 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, British Columbia, and Saskatchewan. Enerplus’ net proved reserves summarized in the following chart represent the Corporation’s lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties:

	Canada		United States		Total		Total
	Oil and	Natural	Oil and	Natural	Oil and	Natural	All
	NGLs	Gas	NGLs	Gas	NGLs	Gas	Products
	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mboe)
Proved Developed and Undeveloped
Reserves at December 31, 2015	35,072	103,232	53,702	298,392	88,774	401,624	155,711
Purchases of reserves in place	1,434	12,228	—	—	1,434	12,228	3,472
Sales of reserves in place	(2,954)	(49,069)	(4,204)	(2,998)	(7,158)	(52,067)	(15,836)
Discoveries and extensions	83	—	12,515	28,288	12,598	28,288	17,313
Revisions of previous estimates	(234)	9,556	(7,722)	100,812	(7,956)	110,368	10,439
Improved recovery	—	—	—	—	—	—	—
Production	(4,391)	(26,526)	(8,465)	(64,588)	(12,856)	(91,114)	(28,042)
Proved Developed and Undeveloped
Reserves at December 31, 2016	29,009	49,421	45,826	359,906	74,835	409,327	143,056
Purchases of reserves in place	—	—	—	—	—	—	—
Sales of reserves in place	(2,412)	(10,332)	(111)	(86)	(2,523)	(10,418)	(4,260)
Discoveries and extensions	1,373	450	34,213	51,369	35,586	51,819	44,223
Revisions of previous estimates	2,841	12,247	2,771	124,796	5,612	137,043	28,453
Improved recovery	—	—	—	—	—	—	—
Production	(3,428)	(15,235)	(8,429)	(63,526)	(11,857)	(78,761)	(24,984)
Proved Developed and Undeveloped
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
Proved Developed Reserves
December 31, 2015	30,517	101,665	38,572	288,684	69,089	390,349	134,147
December 31, 2016	25,743	48,243	33,799	350,294	59,542	398,537	125,965
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
Proved Undeveloped Reserves
December 31, 2015	4,555	1,567	15,130	9,708	19,685	11,275	21,564
December 31, 2016	3,267	1,178	12,027	9,612	15,294	10,790	17,092
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

Purchases of reserves in place

In 2016, the Company acquired working interests in the Ante Creek North oil property located in Alberta. This purchase represented all of the purchase of reserves in place for Enerplus in 2016.

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.

Sales of reserves in place

In 2016, the Company sold working interests in developed and undeveloped land in six oil properties located in Alberta and 12 natural gas properties located in Alberta and Saskatchewan.

Additionally, the Company sold almost all of its non-operated working interests in the Bakken/Three Forks crude oil property in North Dakota, which accounts for all of the United States sales of reserves in place for 2016.

In 2017, the Company sold working interests in developed and undeveloped land in nine oil properties and 39 natural gas properties located in Alberta and Saskatchewan.

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

In 2018, the Company 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.

Discoveries and extensions

 United States discoveries and extensions in the Company's Bakken/Three Forks crude oil property in North Dakota, and the Marcellus natural gas property in Pennsylvania for the period ending December 31, 2016 were primarily due to successful well development. In 2017, discoveries and extensions in these properties were primarily due to improved constant pricing and also successful well development. In 2018, discoveries and extensions in these properties were primarily due to successful well development. In these periods, the Company added 12,515 Mbbl, 34,213 Mbbl and 24,791 Mbbl of net proved oil and NGLs reserves with respect to Bakken/Three Forks properties in 2016, 2017 and 2018, respectively. The Company added 22,017 MMcf , 34,618 MMcf and 52,880 MMcf of net proved natural gas reserves in 2016, 2017 and 2018, respectively, in the Marcellus natural gas property.

In 2016, Canadian discoveries and extensions accounted for an increase of 83 Mbbl of net proved oil and NGLs reserves due to assigning reserves to a location in the Saskatchewan Ratcliffe oil property.

In 2017, Canadian discoveries and extensions accounted for an increase of 1,373 Mbbl of net proved oil and NGLs reserves and 450 MMcf of net proved natural gas reserves in the Medicine Hat Glauconitic C polymer flood and Cadogan oil properties located in Alberta, and the Saskatchewan Ratcliffe oil property.

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

Revisions of previous estimates

In 2016, negative revisions to United States oil reserves were primarily due to the removal of undeveloped locations that would not be drilled within five years of initial booking. Positive revisions to United States natural gas reserves were primarily due to improved production performance of the Marcellus natural gas property.

In 2017, positive revisions to United States oil reserves and United States natural gas reserves were primarily due to an increase in the constant oil price forecast versus 2016.

In 2018, positive revisions to United States oil reserves were primarily due to an increase in the constant oil price forecast versus 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 versus 2017.

In 2016, the positive revisions to Canadian natural gas reserves were due to a slightly higher gas price forecast and slightly lower operating costs.

In 2017, the positive revisions to both Canadian oil and natural gas reserves were primarily due to an increase in the constant oil and gas price forecasts versus 2016.

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

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 oil and NGLs reserves and 17 MMcf of net proved natural gas reserves.

B. CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

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

	2018		2017		2016
	(in $ thousands)
Capitalized costs(1)	$	14,773,082	$	13,622,266	$	13,567,390
Less accumulated depletion, depreciation and impairment		(13,479,141)		(12,732,299)		(12,840,938)
Net capitalized costs	$	1,293,941	$	889,967	$	726,452

Note:

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

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

Costs incurred in connection with oil and gas producing activities are presented in the table below. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire 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 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, 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

	For the Year Ended December 31, 2017
	Canada		United States			Total
	(in $ thousands)
Acquisition of properties:
Proved	$	—	$		—	$	—
Unproved		4,661			8,615		13,276
Exploration costs		2,131			571		2,702
Development costs		66,477			403,798		470,275
	$	73,269	$		412,984	$	486,253
	For the Year Ended December 31, 2016
	Canada			United States		Total

	(in $ thousands)
Acquisition of properties:
Proved	$	49,043	$	1,847	$	50,890
Unproved		65,401		9,835		75,236
Exploration costs		740		2,158		2,898
Development costs		52,704		162,427		215,131
	$	167,888	$	176,267	$	344,155

D. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to Enerplus' oil and gas producing activities for the years ended December 31, 2018, 2017 and 2016:

	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 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

	For the Year Ended December 31, 2017
	Canada		United States		Total
	(in $ thousands)
Revenue
Sales(1)	$	227,031	$	693,662	$	920,693
Deduct(2)
Production costs(3)		98,057		264,627		362,684
Depletion, depreciation and accretion (“DD&A”)		89,937		160,837		250,774
Current and deferred income tax provision (recovery)		(17,534)		99,522		81,988
Results of operations for oil and gas producing activities	$	56,571	$	168,676	$	225,247
DD&A per net BOE unit of production	$	15.07	$	8.46	$	10.04

	For the Year Ended December 31, 2016
	Canada		United States		Total
	(in $ thousands)
Revenue
Sales(1)	$	233,391	$	489,341	$	722,732
Deduct(2)
Production costs(3)		151,151		241,330		392,481
Depletion, depreciation and accretion (“DD&A”)		126,061		202,903		328,964
Impairment		89,359		211,812		301,171
Current and deferred income tax provision (recovery)		(24,376)		(212,822)		(237,198)
Results of operations for oil and gas producing activities	$	(108,804)	$	46,118	$	(62,686)
DD&A per net BOE unit of production	$	14.31	$	10.55	$	11.73

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 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 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, 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	$	3,158	$	3,722
Deduction: 10% annual discount factor		206		1,177		1,383
Standardized measure of discounted future net cash flows	$	357	$	1,981	$	2,338

	As at December 31, 2017
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	1,383	$	4,360	$	5,743
Future production costs		654		1,553		2,207
Future development and asset retirement costs		126		895		1,021
Future income tax expenses		—		24		24
Future net cash flows	$	603	$	1,888	$	2,491
Deduction: 10% annual discount factor		233		717		950
Standardized measure of discounted future net cash flows	$	370	$	1,171	$	1,540

	As at December 31, 2016
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	1,171	$	2,073	$	3,243
Future production costs		660		1,025		1,685
Future development and asset retirement costs		237		308		546
Future income tax expenses		—		—		—
Future net cash flows	$	273	$	739	$	1,012
Deduction: 10% annual discount factor		81		241		322
Standardized measure of discounted future net cash flows	$	192	$	498	$	690

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

	2018		2017		2016
	(in $ millions)
Beginning of year	$	1,540	$	690	$	944
Sales of oil and natural gas produced, net of production costs		(844)		(557)		(329)
Net changes in sales prices and production costs		1,195		1,030		(432)
Changes in previously estimated development costs incurred during the period		594		457		205
Changes in estimated future development costs		(892)		(843)		1
Extension, discoveries and improved recovery, net of related costs		978		455		78
Purchase of reserves in place		2		—		42
Sales of reserves in place		(2)		—		(106)
Net change resulting from revisions in previous quantity estimates		(114)		262		188
Accretion of discount		143		61		79
Net change in income taxes		(247)		(8)		—
Other significant factors (Exchange rate)		(15)		(6)		22
End of year	$	2,338	$	1,540	$	690