Report of Foreign Issuer (6-k)

FORM 6-K

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 August, 2020

COMMISSION FILE NUMBER 1-15150

The Dome Tower

Suite 3000, 333 – 7^th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

(403) 298-2200

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F ◻ Form 40-F ⌧

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)

Yes ◻ No ⌧

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)

Yes ◻ No ⌧

EXHIBIT INDEX

EXHIBIT 99.1 — Management’s Discussion and Analysis for the Second Quarter ended June 30, 2020

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Second Quarter ended June 30, 2020

EXHIBIT 99.3 — Certification of the Chief Executive Officer

EXHIBIT 99.4 — Certification of the Chief Financial Officer

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: August 7, 2020

MD&A

Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)

The following discussion and analysis of financial results is dated August 6, 2020 and is to be read in conjunction with:

●	the unaudited interim condensed consolidated financial statements of Enerplus Corporation (“Enerplus” or the “Company”) as at and for the three and six months ended June 30, 2020 and 2019 (the “Interim Financial Statements”);

●	the audited consolidated financial statements of Enerplus as at December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017; and

●	our MD&A for the year ended December 31, 2019 (the “Annual MD&A”).

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non-GAAP Measures” at the end of the MD&A for further information. In addition, the following MD&A contains disclosure regarding certain risks and uncertainties associated with Enerplus' business. See "Risk Factors and Risk Management" in this MD&A and in the Annual MD&A and "Risk Factors" in Enerplus' annual information form for the year ended December 31, 2019 (the "Annual Information Form”).

BASIS OF PRESENTATION

The Interim Financial Statements and Notes thereto have been prepared in accordance with U.S. GAAP, including the prior period comparatives. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements. Certain prior period amounts have been restated to conform with current period presentation.

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 bbl and oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcf. BOE and Mcfe measures are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1 or 0.167:1, as applicable, utilizing a conversion on this basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. Unless otherwise stated, all production volumes and realized product prices information is presented on a “Company interest” basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests. Company interest is not a term defined in Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and may not be comparable to information produced by other entities. All references to "liquids" in this MD&A include light and medium crude oil, heavy oil and tight oil (all together referred to as "crude oil") and natural gas liquids on a combined basis.

In accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under International Financial Reporting Standards, industry standard is to present oil and gas sales before deduction of royalties, and as such, this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our Canadian peers.

OVERVIEW

The onset of the coronavirus (“COVID-19”) pandemic in mid-March resulted in a sudden global economic downturn and significant challenges for our industry. In response to a dramatic decline in crude oil demand and historically low prices, we began temporarily curtailing production from certain wells across our crude oil and natural gas liquids properties and suspended our operated drilling and completions activity in North Dakota during the second quarter.

As a result, our crude oil and natural gas liquids production decreased 12% to 48,097 bbls/day, compared to 54,390 bbls/day in the first quarter of 2020. Total average production of 87,360 BOE/day in the second quarter was also impacted by limited capital activity in the Marcellus, with natural gas production of 196,738 Mcf/day, a 9% decrease from the first quarter of 2020, and in line with our previous rest of year expectation of 185 MMcf/day to 200 MMcf/day.

Late in the second quarter, both energy equities and commodity prices began to stabilize as global economies began to reopen, with WTI benchmark prices averaging US$38.31/bbl in June, a 129% increase compared to an average of US$16.70/bbl in April. We began restoring curtailed production in June as crude oil prices improved, with production largely restored in July. Although markets remain volatile and there is uncertainty surrounding the timing of a full economic recovery, global crude oil demand has begun to improve. As a result, we are reinstating our 2020 annual guidance.

ENERPLUS 2020 Q2 REPORT 1

We expect annual 2020 production to average 88,000 - 90,000 BOE/day, including 49,000 - 50,000 bbls/day of crude oil and natural gas liquids. We are maintaining our capital spending budget of $300 million. Remaining activity is primarily focused on non-operated drilling and completions in the Marcellus and North Dakota, along with four operated completions in North Dakota during the fourth quarter. We expect to complete approximately six net wells in North Dakota and two net wells in the Marcellus in the second half of 2020.

Capital expenditures during the second quarter of 2020 totaled $40.1 million compared to $163.6 million during the first quarter, with approximately 68% of our annual capital budget spent year to date.

Our Bakken crude oil price differential narrowed to US$4.36/bbl below WTI during the second quarter, a 17% improvement compared to US$5.26/bbl below WTI during the first quarter. Although Bakken differentials were very weak in April due to the COVID-19 demand reductions, the weak pricing was temporary as regional production was significantly reduced in May and June in response. These industry-wide production curtailments, along with our own decision to curtail some production as prices fell, impacted the supply in the basin enough to provide support for local prices through the end of the quarter. We currently expect our annual Bakken crude oil price differential to average US$5.00/bbl below WTI. This guidance assumes the continued operation of the Dakota Access Pipeline (“DAPL”), which is currently the subject of ongoing litigation.

Our Marcellus natural gas price differential widened to US$0.49/Mcf below NYMEX in the second quarter compared to US$0.38/Mcf below NYMEX during the first quarter with lower seasonal demand. We continue to expect our Marcellus natural gas price differential to average US$0.45/Mcf below NYMEX for 2020.

Operating costs for the quarter were $54.4 million or $6.84/BOE, compared to $79.0 million or $8.84/BOE in the first quarter, mainly due to lower production and less well servicing activity in the second quarter of 2020. We continue to expect average annual operating costs of $8.25/BOE.

We expect annual cash general and administrative expenses of $1.40/BOE, transportation costs of $4.15/BOE and an annual average royalty and production tax rate of 26% of oil and natural gas sales before transportation.

We reported a net loss of $609.3 million in the second quarter of 2020 compared to net income of $2.9 million in the first quarter of 2020. The decrease was primarily due to impairments recorded in the second quarter as a result of the continued market volatility and low commodity price environment, which included a $426.8 million non-cash impairment on our property, plant and equipment (“PP&E”) and a $202.8 million non-cash impairment on our goodwill. Net loss in the second quarter was also impacted by a $10.9 million loss on commodity derivative instruments and a total tax recovery of $113.4 million, compared to a $131.3 million gain on commodity derivative instruments and a total tax expense of $109.4 million recorded in the first quarter of 2020.

Cash flow from operations decreased to $90.6 million in the second quarter compared to $122.7 million in the first quarter of 2020, and adjusted funds flow decreased to $70.0 million from $113.2 million over the same period. The decrease was primarily due to a decline in realized prices and lower production during the quarter, offset by a $20.5 million increase in realized commodity derivative gains compared to the first quarter of 2020.

We continue to expect our commodity hedging program to protect a significant portion of our cash flow from operating activities and adjusted funds flow. At June 30, 2020, our crude oil commodity derivative contracts were in a net asset position of $44.0 million. As of August 6, 2020, we have hedged 24,500 bbls/day of crude oil for the remainder of 2020, and 6,000 bbls/day for 2021.

Despite the ongoing challenging market conditions, we have maintained a strong balance sheet. At June 30, 2020, total debt net of cash was $518.1 million, including senior notes of $523.2 million and cash on hand of $6.2 million, and our net debt to adjusted funds flow ratio was 1.0x. We made principal repayments of US$81.6 million on our senior notes during the second quarter. At June 30, 2020 and as of the date of this MD&A, we are in compliance with all debt covenants.

2 ENERPLUS 2020 Q2 REPORT

RESULTS OF OPERATIONS

Production

Daily production for the second quarter averaged 87,360 BOE/day, a decrease of 11% compared to average production of 98,209 BOE/day in the first quarter of 2020. Crude oil and natural gas liquids production decreased by 12% to 48,097 bbls/day primarily due to the temporary curtailment of certain wells across our crude oil and liquids properties during the second quarter in order to protect against selling production at negative margins. Second quarter production was further impacted by a reduction to the 2020 capital program, which suspended operated drilling and completions activity in North Dakota in mid-April. Natural gas production decreased 10% to 235,579 Mcf/day compared to 262,913 Mcf/day during the first quarter due to minimal capital activity in the Marcellus.

For the three months ended June 30, 2020, total production decreased by 13,334 BOE/day or 13%, compared to the same period in 2019, primarily due to the impact of price related crude oil and natural gas liquids production curtailments and the suspension of our operated North Dakota drilling and completions program during the second quarter of 2020.

For the six months ended June 30, 2020, total production decreased by 1,887 BOE/day or 2% compared to the same period in 2019. The decrease was mainly due to a 9% decline in natural gas production as a result of limited capital activity in the Marcellus and our decision to shut-in, abandon and reclaim our Canadian natural gas property in Tommy Lakes during the first quarter of 2020. Crude oil and natural gas liquids production increased 4% over the same period, with the impact of continued capital spending on our U.S. crude oil properties during the second half of 2019 and the first quarter of 2020 more than offsetting the impact of lower production during the second quarter of 2020.

Our crude oil and natural gas liquids weighting increased to 55% in the first six months of 2020 from 52% for the same period in 2019.

Average daily production volumes for the three and six months ended June 30, 2020 and 2019 are outlined below:


	Three months ended June 30,			Six months ended June 30,
Average Daily Production Volumes	2020	2019	% Change	2020	2019	% Change
Crude oil (bbls/day)	43,168	48,141	(10%)	46,106	44,642	3%
Natural gas liquids (bbls/day)	4,929	4,720	4%	5,137	4,552	13%
Natural gas (Mcf/day)	235,579	287,000	(18%)	249,246	272,863	(9%)
Total daily sales (BOE/day)	87,360	100,694	(13%)	92,784	94,671	(2%)

We are providing annual average production guidance for 2020 of 88,000 - 90,000 BOE/day, including 49,000 - 50,000 bbls/day of crude oil and natural gas liquids. This annual production guidance is based on a capital budget of $300 million, which includes the completion of approximately six net wells in North Dakota and two net wells in the Marcellus in the second half of 2020.

ENERPLUS 2020 Q2 REPORT 3

Pricing

The prices received for crude oil and natural gas production directly impact our earnings, cash flow from operations, adjusted funds flow and financial condition. The following table compares quarterly average prices from the first half of 2020 to the first half of 2019 and other periods indicated:


	Six months ended June 30,
Pricing (average for the period)	2020		2019		Q2 2020		Q1 2020			Q4 2019		Q3 2019		Q2 2019
Benchmarks
WTI crude oil (US$/bbl)	$	37.01	$	57.36	$	27.85	$	46.17	$	56.96	$	56.45	$	59.81
Brent (ICE) crude oil (US$/bbl)		42.12		66.11		33.27		50.96		62.51		62.00		68.32
NYMEX natural gas – last day (US$/Mcf)		1.83		2.89		1.72		1.95		2.50		2.23		2.64
USD/CDN average exchange rate		1.37		1.33		1.39		1.34		1.32		1.32		1.34
USD/CDN period end exchange rate		1.36		1.31		1.36		1.41		1.30		1.32		1.31

Enerplus selling price⁽¹⁾
Crude oil ($/bbl)	$	41.59	$	70.82	$	30.55	$	51.30	$	67.23	$	67.76	$	74.42
Natural gas liquids ($/bbl)		6.16		18.53		(0.96)		12.72		18.28		5.97		17.96
Natural gas ($/Mcf)		1.87		3.46		1.63		2.08		2.50		2.13		2.63

Average differentials
Bakken DAPL – WTI (US$/bbl)	$	(5.29)	$	(2.64)	$	(5.24)	$	(5.34)	$	(5.59)	$	(2.97)	$	(2.36)
Brent (ICE) – WTI (US$/bbl)		5.11		8.75		5.42		4.79		5.55		5.55		8.51
MSW Edmonton – WTI (US$/bbl)		(6.86)		(4.74)		(6.14)		(7.58)		(5.37)		(4.66)		(4.63)
WCS Hardisty – WTI (US$/bbl)		(16.00)		(11.48)		(11.47)		(20.53)		(15.83)		(12.24)		(10.67)
Transco Leidy monthly – NYMEX (US$/Mcf)		(0.39)		(0.33)		(0.38)		(0.39)		(0.70)		(0.48)		(0.43)
Transco Z6 Non-New York monthly – NYMEX (US$/Mcf)		(0.21)		0.68		(0.29)		0.41		(0.11)		(0.35)		(0.31)

Enerplus realized differentials⁽¹⁾⁽²⁾
Bakken crude oil – WTI (US$/bbl)	$	(4.87)	$	(3.10)	$	(4.36)	$	(5.26)	$	(4.40)	$	(3.61)	$	(3.00)
Marcellus natural gas – NYMEX (US$/Mcf)		(0.44)		(0.25)		(0.49)		(0.38)		(0.63)		(0.44)		(0.57)
Canada crude oil – WTI (US$/bbl)		(16.34)		(10.21)		(14.49)		(17.77)		(14.80)		(13.50)		(9.99)

(1)	Excluding transportation costs, royalties and the effects of commodity derivative instruments.

(2)	Based on a weighted average differential for the period.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our realized crude oil sales price for the second quarter of 2020 averaged $30.55/bbl, a decrease of 40% compared to the first quarter, and in line with the decline in the benchmark WTI price over the same period. The decrease was the result of the combined impact of global demand destruction resulting from the COVID-19 pandemic and a dramatic increase in the supply of Russian and Saudi Arabian crude oil in the market after the Organization of the Petroleum Exporting Countries Plus (“OPEC+”) nations failed to agree on production restrictions during the first quarter. As global supply curtailments took hold through the second quarter and with the slow reopening of global economies supporting crude oil demand, WTI prices stabilized and recovered from an average of US$16.70/bbl in April to an average of US$38.31/bbl in June.

Crude oil price differentials were also volatile during the quarter. Our realized Bakken differential improved by US$0.90/bbl during the second quarter of 2020 compared to the first quarter to average US$4.36/bbl below WTI. Differentials weakened significantly during April as refineries reduced purchases given the significant reduction in demand for end products with COVID-19 related lockdowns. Despite this weakness, we outperformed the benchmark index by temporarily curtailing production during the weakest period and through a diversification of sales into higher priced markets. Our Bakken sales price consists of a combination of in-basin monthly spot and index sales, term physical sales with fixed differential pricing versus WTI and/or Brent, and sales at the U.S. Gulf Coast delivered via firm capacity on DAPL.

In early July, a U.S. district court ordered DAPL to cease operations after it found that, due to deficiencies in the original environmental review, the U.S. Army Corps of Engineers are required to complete a more thorough Environmental Impact Statement. On August 5, an appeals court granted the pipeline owners’ request for a stay over the lower court order requiring the pipeline to cease operations. As a result, there is no outstanding court order in place requiring DAPL to shut down at this time and the legal process is ongoing.

As a result of the above and assuming DAPL continues to operate, we expect the market price for Bakken crude oil to remain constructive and expect our annual Bakken crude oil price differential to average approximately US$5.00/bbl below WTI in 2020. For the second half of 2020, we have fixed differential sales agreements in North Dakota for approximately 16,000 bbls/day at an estimated price of approximately US$6.00/bbl below WTI, based on current market prices.

4 ENERPLUS 2020 Q2 REPORT

Our realized price differential for Canadian crude oil production narrowed by US$3.28/bbl compared to the first quarter of 2020, which was in line with changes to the underlying benchmark prices for Canadian crude oil.

Our realized sales price for natural gas liquids averaged ($0.96)/bbl during the second quarter of 2020. Natural gas liquids price weakness was mainly attributable to a prior period pricing adjustment and the deterioration of benchmark pricing.

NATURAL GAS

Our realized natural gas sales price averaged $1.63/Mcf during the second quarter, a decrease of 22% compared to the first quarter of 2020. NYMEX benchmark prices fell 12% over the same period. The price weakness was mainly due to lower shoulder season demand as we transitioned from winter to spring. Additionally, an oversupply in the global LNG market has reduced North American LNG exports which effectively added more supply to North American natural gas markets. Our realized Marcellus sales price differential averaged US$0.49/Mcf below NYMEX during the quarter, compared to US$0.38/Mcf in the first quarter of 2020, reflecting seasonal weakness in local market price differentials over the period. Prices for Transco Zone 6 Non-New York averaged US$0.29/Mcf below NYMEX in the second quarter. By comparison, this market traded at a significant premium to NYMEX during the first quarter of 2020. This seasonal transition in localized Non-New York pricing resulted in weaker price realizations during the second quarter as expected. We continue to expect our Marcellus natural gas price differential to average US$0.45/Mcf below NYMEX in 2020.

FOREIGN EXCHANGE

Our oil and natural gas sales are impacted by foreign exchange fluctuations as the majority of our sales are based on U.S. dollar denominated benchmark indices. A weaker Canadian dollar increases the amount of our realized sales, as well as the amount of our U.S. denominated costs, such as capital, interest on our U.S. denominated debt, and the value of our outstanding U.S. senior notes.

The Canadian dollar weakened significantly during the first six months of 2020 in response to lower commodity prices as a result of the global excess supply of crude oil and the decreased demand impact of the COVID-19 pandemic. The USD/CDN exchange rate peaked at 1.45 USD/CDN in March and remained volatile throughout the second quarter of 2020, resulting in an average exchange rate of 1.37 USD/CDN during the first six months of 2020 compared to 1.33 USD/CDN for the same period in 2019. The Canadian dollar weakened to 1.36 USD/CDN at June 30, 2020, compared to 1.30 USD/CDN at December 31, 2019.

Price Risk Management

We have a price risk management program that considers our overall financial position and the economics of our capital program.

As of August 6, 2020, we have hedged 24,500 bbls/day of crude oil for the remainder of 2020, and 6,000 bbls/day for the first half of 2021. Our crude oil hedges are a mix of swaps, put spreads and three way collars in 2020, and strictly three way collars in 2021. The put spreads and three way collars provide us with exposure to significant upward price movement; however, the sold put effectively limits the amount of downside protection we have to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our cash flow from operating activities and adjusted funds flow.

The following is a summary of our financial contracts in place at August 6, 2020:


	WTI Crude Oil (US$/bbl)
		Jul 1, 2020 – Sep 30, 2020	Oct 1, 2020 – Dec 31, 2020	Jan 1, 2021 – Jun 30, 2021
Swaps
Volume (bbls/day)		7,000	—	—
Sold Swaps		$ 36.02	—	—

Put Spreads⁽¹⁾
Volume (bbls/day)		16,000	16,000	—
Sold Puts⁽²⁾		$ 46.88	$ 46.88	—
Purchased Puts		$ 57.50	$ 57.50	—

Three Way Collars⁽¹⁾
Volume (bbls/day)		5,000	5,000	6,000
Sold Puts		$ 48.00	$ 48.00	$ 32.00
Purchased Puts		$ 56.25	$ 56.25	$ 40.00
Sold Calls		$ 65.00	$ 65.00	$ 50.00

(1)	The total average deferred premium spent on our outstanding hedges is US$1.75/bbl from July 1, 2020 to December 31, 2020 and US$0.03/bbl from January 1, 2021 to June 30, 2021.

(2)	The sold puts on the put spreads settle annually at the end of 2020.

ENERPLUS 2020 Q2 REPORT 5

ACCOUNTING FOR PRICE RISK MANAGEMENT


Commodity Risk Management Gains/(Losses)	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Cash gains/(losses):
Crude oil	$	53.5	$	(5.9)	$	86.5	$	(7.8)
Natural gas		—		4.7		—		17.2
Total cash gains/(losses)	$	53.5	$	(1.2)	$	86.5	$	9.4

Non-cash gains/(losses):
Crude oil	$	(64.4)	$	23.6	$	33.9	$	(63.3)
Natural gas		—		5.0		—		(3.5)
Total non-cash gains/(losses)	$	(64.4)	$	28.6	$	33.9	$	(66.8)
Total gains/(losses)	$	(10.9)	$	27.4	$	120.4	$	(57.4)


	Three months ended June 30,				Six months ended June 30,
(Per BOE)	2020		2019		2020		2019
Total cash gains/(losses)	$	6.73	$	(0.13)	$	5.12	$	0.55
Total non-cash gains/(losses)		(8.10)		3.12		2.01		(3.90)
Total gains/(losses)	$	(1.37)	$	2.99	$	7.13	$	(3.35)

We realized cash gains of $53.5 million and $86.5 million, respectively, on our crude oil contracts during the three and six months ended June 30, 2020, compared to realized cash losses of $5.9 million and $7.8 million, respectively, for the same periods in 2019. Cash gains recorded during the six months ended June 30, 2020 were primarily due to prices falling below the swap level as well as the net effect of benchmark prices below the put levels on both our put spreads and three way collars.

As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At June 30, 2020, the fair value of crude oil contracts was in a net asset position of $44.0 million. For the three and six months ended June 30, 2020, the change in the fair value of our crude oil contracts resulted in a loss of $64.4 million and a gain of $33.9 million, respectively. Our natural gas contracts were settled in the fourth quarter of 2019 and there were no natural gas derivative contracts outstanding during the six months ended June 30, 2020.

Revenues


	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Oil and natural gas sales	$	155.3	$	403.2	$	440.9	$	759.6
Royalties		(33.2)		(81.7)		(90.7)		(150.7)
Oil and natural gas sales, net of royalties	$	122.1	$	321.5	$	350.2	$	608.9

Oil and natural gas sales, net of royalties, for the three and six months ended June 30, 2020 were $122.1 million and $350.2 million, respectively, a decrease of 62% and 42% from the same periods in 2019. The decrease in revenue was due to a reduction in realized prices as a result of demand destruction from the COVID-19 pandemic and the Saudi Arabia and Russian price war, along with lower production volumes due to price related curtailments on a portion of our crude oil and natural gas liquids production during the second quarter of 2020. See Note 11 to the Interim Financial Statements for further detail.

Royalties and Production Taxes


	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)	2020		2019		2020		2019
Royalties	$	33.2	$	81.7	$	90.7	$	150.7
Per BOE	$	4.18	$	8.92	$	5.37	$	8.79

Production taxes	$	7.7	$	21.4	$	23.1	$	36.1
Per BOE	$	0.97	$	2.34	$	1.37	$	2.11
Royalties and production taxes	$	40.9	$	103.1	$	113.8	$	186.8
Per BOE	$	5.15	$	11.26	$	6.74	$	10.90

Royalties and production taxes (% of oil and natural gas sales)		26%		26%		26%		25%

6 ENERPLUS 2020 Q2 REPORT

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees and freehold mineral taxes. A large percentage of our production is from U.S. properties where royalty rates are generally higher than in Canada and less sensitive to commodity price levels. Royalties and production taxes for the three and six months ended June 30, 2020 were $40.9 million and $113.8 million, respectively, a decrease of 60% and 39%, respectively, from the same periods in 2019. The decrease was primarily due to lower realized prices, and a decrease in production volumes.

We expect annual royalties and production taxes in 2020 to average 26% of oil and natural gas sales before transportation.

Operating Expenses


	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)	2020		2019		2020		2019
Cash operating expenses	$	54.4	$	71.8	$	133.4	$	141.6
Per BOE	$	6.84	$	7.84	$	7.90	$	8.26

For the three and six months ended June 30, 2020, operating expenses were $54.4 million or $6.84/BOE and $133.4 million or $7.90/BOE, respectively, a decrease of $17.4 million or $1.00/BOE and $8.2 million or $0.36/BOE, respectively, from the same periods in 2019. The decrease was primarily due to the price-related production curtailment of our highest unit expense crude oil wells, along with less well servicing activity and lower service costs compared to the same periods in 2019.

We continue to expect average annual operating costs of $8.25/BOE for 2020.

Transportation Costs


	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)	2020		2019		2020		2019
Transportation costs	$	34.0	$	36.8	$	69.3	$	68.1
Per BOE	$	4.28	$	4.02	$	4.11	$	3.97

For the three and six months ended June 30, 2020, transportation costs were $34.0 million or $4.28/BOE and $69.3 million or $4.11/BOE, respectively, compared to $36.8 million or $4.02/BOE and $68.1 million or $3.97/BOE, respectively, for the same periods in 2019. Transportation costs decreased during the second quarter due to lower production volumes as a result of price related production curtailments. The increase on a per BOE basis was primarily due to the impact of a weaker Canadian dollar on our U.S. dollar denominated transportation costs compared to the same periods in 2019.

We expect annual transportation costs to average $4.15/BOE for 2020.

Netbacks

The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.


	Three months ended June 30, 2020
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	52,198 BOE/day		210,971 Mcfe/day		87,360 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	25.63	$	1.75	$	19.53
Royalties and production taxes		(7.18)		(0.35)		(5.15)
Cash operating expenses		(10.45)		(0.25)		(6.84)
Transportation costs		(3.21)		(0.98)		(4.28)
Netback before hedging	$	4.79	$	0.17	$	3.26
Cash hedging gains/(losses)		11.26		—		6.73
Netback after hedging	$	16.05	$	0.17	$	9.99
Netback before hedging ($ millions)	$	22.7	$	3.3	$	26.0
Netback after hedging ($ millions)	$	76.2	$	3.3	$	79.5

(1)	See “Non-GAAP Measures” in this MD&A

ENERPLUS 2020 Q2 REPORT 7


	Three months ended June 30, 2019
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	56,602 BOE/day		264,554 Mcfe/day		100,694 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	65.29	$	2.78	$	44.00
Royalties and production taxes		(17.51)		(0.54)		(11.26)
Cash operating expenses		(12.54)		(0.30)		(7.84)
Transportation costs		(3.02)		(0.88)		(4.02)
Netback before hedging	$	32.22	$	1.06	$	20.88
Cash hedging gains/(losses)		(1.14)		0.19		(0.13)
Netback after hedging	$	31.08	$	1.25	$	20.75
Netback before hedging ($ millions)	$	166.0	$	25.5	$	191.5
Netback after hedging ($ millions)	$	160.1	$	30.2	$	190.3


	Six months ended June 30, 2020
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	55,716 BOE/day		222,410 Mcfe/day		92,784 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	35.63	$	1.96	$	26.11
Royalties and production taxes		(9.71)		(0.38)		(6.74)
Cash operating expenses		(11.99)		(0.29)		(7.90)
Transportation costs		(3.05)		(0.95)		(4.11)
Netback before hedging	$	10.88	$	0.34	$	7.36
Cash hedging gains/(losses)		8.53		—		5.12
Netback after hedging	$	19.41	$	0.34	$	12.48
Netback before hedging ($ millions)	$	110.4	$	14.0	$	124.4
Netback after hedging ($ millions)	$	196.9	$	14.0	$	210.9


	Six months ended June 30, 2019
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	52,767 BOE/day		251,426 Mcfe/day		94,671 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	62.64	$	3.55	$	44.33
Royalties and production taxes		(16.32)		(0.68)		(10.90)
Cash operating expenses		(13.19)		(0.34)		(8.26)
Transportation costs		(2.90)		(0.89)		(3.97)
Netback before hedging	$	30.23	$	1.64	$	21.20
Cash hedging gains/(losses)		(0.82)		0.38		0.55
Netback after hedging	$	29.41	$	2.02	$	21.75
Netback before hedging ($ millions)	$	288.6	$	74.5	$	363.1
Netback after hedging ($ millions)	$	280.8	$	91.7	$	372.5

(1)	See “Non-GAAP Measures” in this MD&A

Our netbacks in 2020 were impacted by the low commodity price environment. Total netbacks before hedging decreased 86% and 66% during the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019. Our price risk management program continues to provide funds flow protection, with realized cash gains on our crude oil hedging derivatives partially offsetting the impact of lower realized prices and improving total netbacks after hedging.

For the three and six months ended June 30, 2020, our crude oil properties accounted for 87% and 89% of our total netback before hedging, respectively, compared to 87% and 79% during the same periods in 2019.

8 ENERPLUS 2020 Q2 REPORT

General and Administrative (“G&A”) Expenses

Total G&A expenses include share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 12 and Note 15(b) to the Interim Financial Statements for further details.


	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Cash:
G&A expense	$	9.1	$	11.5	$	21.5	$	23.9
Share-based compensation expense		1.2		(0.6)		(1.6)		0.7

Non-Cash:
Share-based compensation expense		3.6		4.3		11.3		12.3
Equity swap loss/(gain)		(0.5)		0.2		1.4		0.1
G&A expense		0.1		0.3		0.1		0.4
Total G&A expenses	$	13.5	$	15.7	$	32.7	$	37.4


	Three months ended June 30,				Six months ended June 30,
(Per BOE)	2020		2019		2020		2019
Cash:
G&A expense	$	1.14	$	1.26	$	1.26	$	1.39
Share-based compensation expense		0.15		(0.07)		(0.09)		0.04

Non-Cash:
Share-based compensation expense		0.45		0.47		0.67		0.72
Equity swap loss/(gain)		(0.06)		0.03		0.08		0.01
G&A expense		0.01		0.03		0.01		0.02
Total G&A expenses	$	1.69	$	1.72	$	1.93	$	2.18

Cash G&A expenses for the three and six months ended June 30, 2020 were $9.1 million or $1.14/BOE and $21.5 million or $1.26/BOE, respectively, compared to $11.5 million or $1.26/BOE and $23.9 million or $1.39/BOE for the same periods in 2019. Cash G&A expenses were lower in part due to government funding received under the Canadian Emergency Wage Subsidy (“CEWS”) program, which reimbursed qualifying Canadian employers for a portion of salaries paid during the six months ended June 30, 2020. Cash G&A expenses during the second quarter were further lowered by cash compensation reductions for our Board of Directors, executives and employees and other non-salary cost saving initiatives.

During the second quarter of 2020, we reported a cash SBC expense of $1.2 million due to the impact of an increase in our share price on outstanding deferred share units. In comparison, during the same period of 2019, we recorded a cash SBC recovery of $0.6 million as a result of a decrease in our share price. We recorded non-cash SBC expense of $3.6 million or $0.45/BOE, a decrease from an expense of $4.3 million, or $0.47/BOE, during the same period in 2019.

We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. In the second quarter of 2020, we recorded a mark-to-market gain of $0.5 million on these contracts, compared to a loss of $0.2 million in the same period in 2019.

Based on cash G&A cost reductions and estimated government funding, we expect annual cash G&A expenses to average approximately $1.40/BOE for 2020.

Interest Expense

For the three and six months ended June 30, 2020, we recorded total interest expense of $7.1 million and $16.0 million, respectively, compared to $8.7 million and $17.1 million for the same periods in 2019. The decrease in interest expense in the second quarter of 2020 was primarily due to the repayment of a portion of our 2009 and 2012 senior notes.

At June 30, 2020, our debt balance consisted primarily of fixed interest rate senior notes, with a weighted average interest rate of 4.6%. See Note 8 to the Interim Financial Statements for further details.

ENERPLUS 2020 Q2 REPORT 9

Foreign Exchange


	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Realized foreign exchange (gain)/loss:
Foreign exchange (gain)/loss on settlements	$	0.1	$	0.1	$	—	$	—
Translation of U.S. dollar cash held in Canada (gain)/loss		0.4		4.1		(2.7)		9.3
Unrealized foreign exchange (gain)/loss		1.0		(16.5)		(1.4)		(33.6)
Total foreign exchange (gain)/loss	$	1.5	$	(12.3)	$	(4.1)	$	(24.3)
USD/CDN average exchange rate		1.39		1.34		1.37		1.33
USD/CDN period end exchange rate		1.36		1.31		1.36		1.31

For the three and six months ended June 30, 2020, we recorded a foreign exchange loss of $1.5 million and a foreign exchange gain of $4.1 million, respectively, compared to gains of $12.3 million and $24.3 million for the same periods in 2019. Realized foreign exchange gains and losses relate primarily to day-to-day transactions recorded in foreign currencies along with the translation of our U.S. dollar denominated cash held in Canada, while unrealized foreign exchange gains and losses are recorded on the translation of our U.S dollar denominated bank debt and working capital held in Canada at each period end.

Effective January 1, 2020, we have designated our outstanding senior notes as a net investment hedge related to our U.S. operations. As a result of the adoption of net investment hedge accounting, any unrealized foreign exchange gains and losses on the translation of this U.S. dollar denominated debt are included in Other Comprehensive Income/(Loss). At June 30, 2020, US$385.4 million of senior notes outstanding were designated as a net investment hedge. For the three and six months ended June 30, 2020, Other Comprehensive Income/(Loss) included an unrealized gain of $19.5 million and a loss of $30.6 million respectively, on our outstanding U.S. dollar denominated senior notes. See Note 3(a) to the Interim Financial Statements for further details.

Capital Investment


	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Capital spending⁽¹⁾	$	40.1	$	207.2	$	203.7	$	368.0
Office capital⁽¹⁾		0.9		2.1		2.8		3.3
Line fill		—		—		—		5.1
Sub-total		41.0		209.3		206.5		376.4
Property and land acquisitions	$	3.4	$	1.9	$	5.7	$	4.9
Property divestments		0.1		(9.6)		(5.5)		(10.1)
Sub-total		3.5		(7.7)		0.2		(5.2)
Total	$	44.5	$	201.6	$	206.7	$	371.2

(1)	Excludes changes in non-cash investing working capital. See Note 18(b) to the Interim Financial Statements for further details.

Capital spending for the three and six months ended June 30, 2020, decreased to $40.1 million and $203.7 million, respectively, compared to $207.2 million and $368.0 million for the same periods in 2019. The decrease was mainly due to the suspension of operated drilling and completions activity in North Dakota during the second quarter of 2020. Capital spending during the second quarter included $31.4 million on our U.S. crude oil properties, $5.8 million on our Marcellus natural gas assets and $3.1 million on our Canadian waterflood properties.

During the second quarter of 2020, we completed $3.4 million in property and land acquisitions, which included minor acquisitions of leases and undeveloped land, compared to $1.9 million for the same period in 2019. We completed a nominal amount of property divestments for the three months ended June 30, 2020, compared to $9.6 million for the same period in 2019, which related to the divestment of properties in Southeastern Saskatchewan.

We are maintaining our capital spending target of $300 million. Remaining activity is primarily focused on non-operated drilling and completions in the Marcellus and North Dakota, with four operated completions in North Dakota in the fourth quarter. In total, we expect to complete approximately six net wells (operated and non-operated) in North Dakota and two net wells in the Marcellus in the second half of 2020.

10 ENERPLUS 2020 Q2 REPORT

Depletion, Depreciation and Accretion (“DD&A”)


	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)	2020		2019		2020		2019
DD&A expense	$	79.9	$	88.3	$	175.1	$	164.2
Per BOE	$	10.05	$	9.64	$	10.37	$	9.58

DD&A of PP&E is recognized using the unit-of-production method based on proved reserves. For the three months ended June 30, 2020, DD&A expense decreased to $79.9 million, compared to $88.3 million in the same period of 2019 as a result of lower overall production volumes. DD&A expense on a per BOE basis increased over the same period as a result of previous capital activity increasing the depletable base.

For the six months ended June 30, 2020, DD&A expense increased to $175.1 million, compared to $164.2 million in the same period of 2019, due to an increase in U.S. crude oil production with higher depletion rates and the impact of a weaker Canadian dollar.

Impairment

PP&E

Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country basis using estimated after-tax future net cash flows discounted at 10 percent from proved reserves using SEC constant prices ("Standardized Measure"). SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. The Standardized Measure is not related to Enerplus' investment criteria and is not a fair value based measurement, but rather a prescribed accounting calculation. Impairments are non-cash and are not reversed in future periods under U.S. GAAP. See Note 6(a) to the Interim Financial Statements for trailing twelve month prices.

Trailing twelve month average crude oil and natural gas prices have been declining throughout the first half of 2020. For the three and six months ended June 30, 2020, we recorded a non-cash PP&E impairment of $426.8 million (Canadian cost centre: $77.5 million, U.S. cost centre: $349.3 million). There were no impairments recorded for the same periods in 2019.

Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the remainder of 2020, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. If commodity prices remain at current levels, the twelve month trailing prices will decline further, impacting the ceiling value and resulting in an increased risk of future PP&E impairments. See "Risk Factors and Risk Management - Risk of Impairment of Oil and Gas Properties, Deferred Tax Assets and Goodwill" in the Annual MD&A and "Risk Factors and Risk Management" in this MD&A.

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes.

Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to the reporting unit’s fair value, with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss). The loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.

During the second quarter of 2020, we recorded a non-cash goodwill impairment charge of $202.8 million related to our U.S. reporting unit. The impairment was a result of the ongoing deterioration in macroeconomic conditions and low commodity prices due to the COVID-19 pandemic, which resulted in a reduction in the fair value of the U.S. reporting unit and a full write down of our U.S. goodwill asset. There was no goodwill impairment during the same period of the prior year. In the fourth quarter of 2019, we recorded a goodwill impairment of $451.1 million representing the full value of the goodwill attributable to our Canadian reporting unit. At June 30, 2020, there was no goodwill remaining on our Condensed Consolidated Balance Sheet.

ENERPLUS 2020 Q2 REPORT 11

Asset Retirement Obligation

In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on the Condensed Consolidated Balance Sheet are based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate and the timing of the costs to be incurred in future periods. We have estimated the net present value of our asset retirement obligation, using a weighted average credit-adjusted risk-free rate of 5.35%, to be $146.2 million at June 30, 2020, compared to $138.0 million at December 31, 2019, using a weighted average credit-adjusted risk-free rate of 5.50%. For the three and six months ended June 30, 2020, asset retirement obligation settlements were $0.3 million and $11.1 million, respectively, compared to $0.5 million and $5.9 million during the same periods in 2019. See Note 9 to the Interim Financial Statements for further details.

Leases

Enerplus recognizes right-of-use (“ROU”) assets and lease liabilities on the Condensed Consolidated Balance Sheet for qualifying leases with a term greater than 12 months. We incur lease payments related to office space, drilling rig commitments, vehicles and other equipment. Total lease liabilities are based on the present value of lease payments over the lease term. Total ROU assets represent our right to use an underlying asset for the lease term. At June 30, 2020, our total lease liability was $43.6 million. In addition, ROU assets of $39.1 million were recorded, which equate to our lease liabilities less lease incentives. See Note 10 to the Interim Financial Statements for further details.

Income Taxes


	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Current tax expense/(recovery)	$	(14.4)	$	(13.9)	$	(14.4)	$	(19.5)
Deferred tax expense/(recovery)		(98.9)		48.8		10.4		30.9
Total tax expense/(recovery)	$	(113.3)	$	34.9	$	(4.0)	$	11.4

For the three and six months ended June 30, 2020, we recorded a current tax recovery of $14.4 million, compared to a recovery of $13.9 and $19.5 million, respectively, for the same periods in 2019. The recovery in the second quarter of 2020 relates to the recognition of our final U.S. Alternative Minimum Tax (“AMT”) refund.

For the three and six months ended June 30, 2020, we recorded a deferred income tax recovery of $98.9 million and an expense of $10.4 million respectively, compared to an expense of $48.8 million and $30.9 million, for the same periods in 2019. The deferred tax recovery in the second quarter was primarily due to lower net income and non-cash PP&E impairments recorded in both Canada and the U.S.

We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not all or a portion of our deferred income tax assets will not be realized. We have considered available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. This assessment is primarily the result of projecting future taxable income using total proved and probable reserves at forecast average prices and costs. For the six months ended June 30, 2020, a valuation allowance of $93.6 million was recorded during the first quarter of 2020 related entirely to our Canadian deferred income tax assets. No valuation allowance was recorded for the six months ended June 30, 2019. Our overall net deferred income tax asset was $367.3 million at June 30, 2020 (December 31, 2019 - $372.5 million).

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility and senior notes, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At June 30, 2020, our senior debt to adjusted EBITDA ratio was 1.0x and our net debt to adjusted funds flow ratio was 1.0x. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate liquidity.

At June 30, 2020, we had $6.2 million of cash on hand. Total debt net of cash at June 30, 2020, was $518.1 million, an increase of 14% compared to $455.0 million at December 31, 2019. The increase when compared to December 31, 2019 was primarily due to the impact of a weaker Canadian dollar on our U.S. dollar denominated debt and a decrease in cash from $151.6 million at December 31, 2019. During the second quarter, we made scheduled principal repayments of US$81.6 million on our 2009 and 2012 senior notes using our cash on hand, which resulted in a $114.0 million decrease to our outstanding senior notes at June 30, 2020, compared to December 31, 2019.

12 ENERPLUS 2020 Q2 REPORT

Our adjusted payout ratio, which is calculated as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow, was 68% and 120% for the three and six months ended June 30, 2020 respectively, compared to 116% and 110% for the same periods in 2019.

Our working capital deficiency, excluding cash and current derivative financial assets and liabilities, increased to $217.6 million at June 30, 2020, from $210.4 million at December 31, 2019. We expect to finance our working capital deficit and our ongoing working capital requirements through cash on hand, cash flow from operations and our bank credit facility. We continue to expect to be able to meet our financial commitments, as disclosed under “Commitments” in the Annual MD&A.

During the first quarter of 2020, we repurchased and cancelled 340,434 common shares for total consideration of $2.5 million under our Normal Course Issuer Bid (“NCIB”), prior to its expiry on March 25, 2020. Given the current environment, we chose not to renew our NCIB in order to preserve capital and maintain our balance sheet strength and liquidity. We plan to renew our NCIB in due course and recommence our share repurchase program when market conditions improve.

At June 30, 2020, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. We expect to manage our business within these financial ratios during 2020. If we exceed or anticipate exceeding our covenants, we may be required to repay, refinance or renegotiate the terms of the debt. See "Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief" in the Annual Information Form and "Risk Factors and Risk Management" in this MD&A. Our bank credit facility and senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.

The following table lists our financial covenants as at June 30, 2020:


Covenant Description		June 30, 2020
Bank Credit Facility:	Maximum Ratio
Senior debt to adjusted EBITDA⁽¹⁾	3.5x	1.0x
Total debt to adjusted EBITDA ⁽¹⁾	4.0x	1.0x
Total debt to capitalization	55%	22%

Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA⁽¹⁾⁽²⁾	3.0x - 3.5x	1.0x
Senior debt to consolidated present value of total proved reserves⁽³⁾	60%	17%
	Minimum Ratio
Adjusted EBITDA to interest ⁽¹⁾	4.0x	16.6x

Definitions

“Senior debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, impairment and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended June 30, 2020 was $62.2 million and $545.1 million, respectively.

“Total debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.

Footnotes

(1)	See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.

(2)	Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(3)	Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

Dividends


	Three months ended June 30,				Six months ended June 30,
($ millions, except per share amounts)	2020		2019		2020		2019
Dividends to shareholders⁽¹⁾	$	6.7	$	7.0	$	13.3	$	14.2
Per weighted average share (Basic)	$	0.03	$	0.03	$	0.06	$	0.06

(1)	Excludes changes in non-cash financing working capital. See Note 18(b) to the Interim Financial Statements for further details.

During the three and six months ended June 30, 2020, we reported total dividends of $6.7 million or $0.03 per share and $13.3 million or $0.06 per share, respectively, compared to $7.0 million or $0.03 per share and $14.2 million or $0.06 per share for the same periods in 2019. Dividends to shareholders have decreased compared to the same period in 2019 as a result of our share repurchase program.

The dividend is part of our current strategy to return capital to shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

ENERPLUS 2020 Q2 REPORT 13

Shareholders’ Capital


	Six months ended June 30,
	2020		2019
Share capital ($ millions)	$	3,097.0	$	3,225.6

Common shares outstanding (thousands)		222,548		231,616
Weighted average shares outstanding – basic (thousands)		222,457		237,197
Weighted average shares outstanding – diluted (thousands)		222,457		239,947

For the six months ended June 30, 2020, a total of 2,044,718 units vested pursuant to our treasury settled LTI plans, including the impact of performance multipliers (2019 – 1,007,234). In total, 1,160,000 shares were issued from treasury and $13.8 million was transferred from paid-in capital to share capital (2019 – 564,000; $4.4 million). We elected to cash settle the remaining units related to the required tax withholdings (2020 – $7.2 million, 2019 – $5.0 million).

During the six months ended June 30, 2020, the Company repurchased 340,434 common shares under the previous NCIB at an average price of $7.44 per share, for total consideration of $2.5 million (2019 – 8,358,821; $90.4 million). Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit (2019 – $116.4 million; $26.0 million). There were no share repurchases during the three months ended June 30, 2020, as we chose not to renew our NCIB after its expiry on March 25, 2020, in order to preserve capital and maintain our balance sheet strength and liquidity.

At August 6, 2020, we had 222,547,600 common shares outstanding. In addition, an aggregate of 6,960,901 common shares may be issued to settle outstanding grants under the Performance Share Unit (“PSU”) and Restricted Share Unit plans assuming the maximum performance multiplier of 2.0 times for the PSUs.

For further details, see Note 15 to the Interim Financial Statements.

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS


	Three months ended June 30, 2020						Three months ended June 30, 2019
($ millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes⁽¹⁾
Crude oil (bbls/day)		6,066		37,102		43,168		8,749		39,392		48,141
Natural gas liquids (bbls/day)		613		4,316		4,929		931		3,789		4,720
Natural gas (Mcf/day)		12,315		223,264		235,579		23,120		263,880		287,000
Total average daily production (BOE/day)		8,731		78,629		87,360		13,533		87,161		100,694

Pricing⁽²⁾
Crude oil (per bbl)	$	19.57	$	32.35	$	30.55	$	67.12	$	76.04	$	74.42
Natural gas liquids (per bbl)		15.17		(3.25)		(0.96)		25.31		16.16		17.96
Natural gas (per Mcf)		2.19		1.60		1.63		1.82		2.71		2.63

Capital Expenditures
Capital spending	$	2.9	$	37.2	$	40.1	$	7.0	$	200.2	$	207.2
Acquisitions		0.4		3.0		3.4		1.1		0.8		1.9
Divestments		0.1		—		0.1		(9.4)		(0.2)		(9.6)

Netback⁽³⁾ Before Hedging
Oil and natural gas sales	$	14.7	$	140.6	$	155.3	$	60.1	$	343.1	$	403.2
Royalties		(1.7)		(31.5)		(33.2)		(12.7)		(69.0)		(81.7)
Production taxes		0.1		(7.8)		(7.7)		(0.2)		(21.2)		(21.4)
Cash operating expenses		(11.3)		(43.1)		(54.4)		(17.5)		(54.3)		(71.8)
Transportation costs		(1.7)		(32.3)		(34.0)		(2.6)		(34.2)		(36.8)
Netback before hedging	$	0.1	$	25.9	$	26.0	$	27.1	$	164.4	$	191.5

Other Expenses
Asset impairment	$	77.5	$	349.3	$	426.8	$	—	$	—	$	—
Goodwill impairment		—		202.8		202.8		—		—		—
Commodity derivative instruments loss/(gain)		10.9		—		10.9		(27.4)		—		(27.4)
Total G&A⁽⁴⁾		(0.4)		13.9		13.5		(1.9)		17.6		15.7
Current income tax expense/(recovery)		—		(14.4)		(14.4)		(13.9)		—		(13.9)

(1)	Company interest volumes.

(2)	Before transportation costs, royalties and the effects of commodity derivative instruments.

(3)	See “Non-GAAP Measures” section in this MD&A.

(4)	Includes share-based compensation expense.

14 ENERPLUS 2020 Q2 REPORT


	Six months ended June 30, 2020						Six months ended June 30, 2019
($ millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes⁽¹⁾
Crude oil (bbls/day)		6,951		39,155		46,106		8,873		35,769		44,642
Natural gas liquids (bbls/day)		661		4,476		5,137		957		3,595		4,552
Natural gas (Mcf/day)		13,614		235,632		249,246		23,730		249,133		272,863
Total average daily production (BOE/day)		9,881		82,903		92,784		13,785		80,886		94,671

Pricing⁽²⁾
Crude oil (per bbl)	$	30.40	$	43.57	$	41.59	$	63.06	$	72.75	$	70.82
Natural gas liquids (per bbl)		19.85		4.13		6.16		30.71		15.29		18.53
Natural gas (per Mcf)		2.18		1.85		1.87		3.26		3.48		3.46

Capital Expenditures
Capital spending	$	14.7	$	189.0	$	203.7	$	24.5	$	343.5	$	368.0
Acquisitions		1.5		4.2		5.7		2.1		2.8		4.9
Divestments		0.1		(5.6)		(5.5)		(9.5)		(0.6)		(10.1)

Netback⁽³⁾ Before Hedging
Oil and natural gas sales	$	47.5	$	393.4	$	440.9	$	121.9	$	637.7	$	759.6
Royalties		(7.4)		(83.3)		(90.7)		(21.7)		(129.0)		(150.7)
Production taxes		(0.2)		(22.9)		(23.1)		(0.9)		(35.2)		(36.1)
Cash operating expenses		(28.9)		(104.5)		(133.4)		(38.4)		(103.2)		(141.6)
Transportation costs		(3.8)		(65.5)		(69.3)		(5.3)		(62.8)		(68.1)
Netback before hedging	$	7.2	$	117.2	$	124.4	$	55.6	$	307.5	$	363.1

Other Expenses
Asset impairment	$	77.5	$	349.3	$	426.8	$	—	$	—	$	—
Goodwill impairment		—		202.8		202.8		—		—		—
Commodity derivative instruments loss/(gain)		(120.4)		—		(120.4)		57.4		—		57.4
Total G&A⁽⁴⁾		(0.6)		33.3		32.7		11.3		26.1		37.4
Current income tax expense/(recovery)		—		(14.4)		(14.4)		(14.0)		(5.5)		(19.5)

(1)	Company interest volumes.

(2)	Before transportation costs, royalties and the effects of commodity derivative instruments.

(3)	See “Non-GAAP Measures” section in this MD&A.

(4)	Includes share-based compensation expense.

QUARTERLY FINANCIAL INFORMATION


	Oil and Natural Gas				Net Income/(Loss) Per Share
($ millions, except per share amounts)	Sales, Net of Royalties		Net Income/(Loss)		Basic		Diluted
2020
Second Quarter	$	122.1	$	(609.3)	$	(2.74)	$	(2.74)
First Quarter		228.1		2.9		0.01		0.01
Total 2020	$	350.2	$	(606.4)	$	(2.73)	$	(2.73)
2019
Fourth Quarter	$	327.0	$	(429.1)	$	(1.93)	$	(1.93)
Third Quarter		318.9		65.1		0.28		0.28
Second Quarter		321.4		85.1		0.36		0.36
First Quarter		287.5		19.2		0.08		0.08
Total 2019	$	1,254.8	$	(259.7)	$	(1.12)	$	(1.12)
2018
Fourth Quarter	$	326.7	$	249.4	$	1.03	$	1.02
Third Quarter		373.6		86.9		0.35		0.35
Second Quarter		327.4		12.4		0.05		0.05
First Quarter		265.0		29.6		0.12		0.12
Total 2018	$	1,292.7	$	378.3	$	1.55	$	1.53

Oil and natural gas sales, net of royalties, decreased to $122.1 million during the second quarter of 2020 compared to $228.1 million in the first quarter of 2020 due to lower realized prices and price related production curtailments. We reported a net loss of $609.3 million during the second quarter of 2020 compared to net income of $2.9 million in the first quarter of 2020. In addition to a decrease in oil and natural gas sales revenue, net loss in the second quarter was impacted by non-cash impairments, including a $426.8 million impairment on our PP&E, a $202.8 million impairment of our U.S. goodwill asset, and a $162.7 million decrease in the fair value of our commodity derivative instruments compared to the first quarter of 2020.

ENERPLUS 2020 Q2 REPORT 15

Oil and natural gas sales, net of royalties, in 2019 were essentially flat when compared to 2018 due to lower realized commodity prices, offset by increased production. We reported a net loss in 2019 due to a non-cash impairment of $451.1 million on our Canadian goodwill asset recorded in the fourth quarter and a loss on commodity derivative instruments of $66.1 million compared to a gain of $88.2 million recorded in 2018.

U.S. Filing Status

Pursuant to U.S. securities regulations, we are required to reassess our U.S. securities filing status annually at June 30. As at June 30, 2020, we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.

RISK FACTORS AND RISK MANAGEMENT

Risks Relating to the Impact of the COVID-19 Pandemic and Continued Weakness and Volatility in Commodity Prices

The global outbreak of the COVID-19 pandemic and the ongoing uncertainty as to the extent and duration of this pandemic, as well as governmental authorities response thereto, has resulted in, and may continue to result in, among other things: increased volatility in financial markets, including credit markets and foreign currency and interest exchange rates; disruptions to global supply chains; labour shortages; reductions in trade volumes; temporary operational restrictions, quarantine orders, business closures and travel bans; an overall slowdown in the global economy; political and economic instability; and civil unrest. In particular, the COVID-19 pandemic has resulted in, and may continue to result in, a reduction in the demand for crude oil and natural gas.

In addition, recent market events and conditions, including excess global crude oil and natural gas supply and decreased global demand due to the COVID-19 pandemic, have caused significant weakness and volatility in commodity prices. While the commodity prices began to stabilize as global economies began to re-open in June, the recent resurgence of COVID-19 cases in certain geographic areas, and the possibility that a resurgence may occur in other areas, has resulted in the re-imposition of certain restrictions noted above by local authorities. This further increases the risk and uncertainty as to the extent and duration of the COVID-19 pandemic and the resultant impact on commodity demand and prices. The overall result of these recent events and conditions could lead to a prolonged period of depressed prices for crude oil and natural gas which may result in further curtailments, voluntary or otherwise. We are continuing to evaluate the impact of the COVID-19 pandemic and the continued commodity environment instability on our business, financial condition and results of operations; however, the full extent of such impact continues to be unknown at this time and will depend on future developments (which are highly uncertain and cannot be predicted with any degree of confidence) and may be adverse and could result, among other things, in PP&E or deferred tax asset impairment, or exceeding our debt covenants, among others. See disclosure under "Impairment – PP&E", “Income Taxes” and "Liquidity and Capital Resources" in this MD&A.

We are also subject to risks relating to the health and safety of our personnel, including the potential for a slowdown or temporary suspension of our operations in locations impacted by an outbreak or further regulatory changes. Such a suspension in operations could also be mandated by governmental authorities in response to the COVID-19 pandemic. This would negatively impact our production volumes, which could adversely impact our business, financial condition and results of operations.

Depending on the extent and duration of the COVID-19 pandemic, it may also have the effect of heightening many of the other risks described in the Annual Information Form and the Annual MD&A.

2020 GUIDANCE


Summary of 2020 Expectations		Target
Capital spending		$300 million
Average annual production		88,000 - 90,000 BOE/day
Average annual crude oil and natural gas liquids production		49,000 - 50,000 bbls/day
Average royalty and production tax rate (% of gross sales, before transportation)		26%
Operating expenses		$8.25/BOE
Transportation costs		$4.15/BOE
Cash G&A expenses		$1.40/BOE


2020 Differential/Basis Outlook⁽¹⁾		Target
Average U.S. Bakken crude oil differential (compared to WTI crude oil)		US$(5.00)/bbl⁽²⁾
Average Marcellus natural gas sales price differential (compared to NYMEX natural gas)		US$(0.45)/Mcf

(1)

Excluding transportation costs

(2)

Guidance is based on the continued operation of DAPL.

16 ENERPLUS 2020 Q2 REPORT

NON-GAAP MEASURES

The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities:

“Netback” is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of crude oil and natural gas assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.


Calculation of Netback	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Oil and natural gas sales	$	155.3	$	403.2	$	440.9	$	759.6
Less:
Royalties		(33.2)		(81.7)		(90.7)		(150.7)
Production taxes		(7.7)		(21.4)		(23.1)		(36.1)
Cash operating expenses		(54.4)		(71.8)		(133.4)		(141.6)
Transportation costs		(34.0)		(36.8)		(69.3)		(68.1)
Netback before hedging	$	26.0	$	191.5	$	124.4	$	363.1
Cash gains/(losses) on derivative instruments		53.5		(1.2)		86.5		9.4
Netback after hedging	$	79.5	$	190.3	$	210.9	$	372.5

“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.


Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Cash flow from operating activities	$	90.6	$	237.0	$	213.3	$	345.9
Asset retirement obligation expenditures		0.3		0.5		11.1		5.9
Changes in non-cash operating working capital		(20.9)		(51.5)		(41.2)		3.0
Adjusted funds flow	$	70.0	$	186.0	$	183.2	$	354.8

“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending.


Calculation of Free Cash Flow	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Adjusted funds flow	$	70.0	$	186.0	$	183.2	$	354.8
Capital spending		(40.1)		(207.2)		(203.7)		(368.0)
Free cash flow	$	29.9	$	(21.2)	$	(20.5)	$	(13.2)

“Adjusted net income/(loss)” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the Company by understanding the impact of certain non-cash items and other items that the Company considers appropriate to adjust given the irregular nature and relevance to comparable companies. Adjusted net income/(loss) is calculated as net income/(loss) adjusted for unrealized derivative instrument gain/loss, asset impairment, unrealized foreign exchange gain/loss, the tax effect of these items, goodwill impairment, the impact of statutory changes to the Company’s corporate tax rate, and the valuation allowance on our deferred income tax assets. There was no asset or goodwill impairments for the three and six months ended June 30, 2019.


Calculation of Adjusted Net Income/(Loss)	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Net income/(loss)	$	(609.3)	$	85.1	$	(606.4)	$	104.3
Unrealized derivative instrument (gain)/loss		63.9		(28.4)		(32.5)		67.0
Asset impairment		426.8		—		426.8		—
Unrealized foreign exchange (gain)/loss		1.0		(16.5)		(1.4)		(33.6)
Tax effect on above items		(126.4)		7.8		(103.0)		(17.1)
Goodwill impairment		202.8		—		202.8		—
Income tax rate adjustment on deferred taxes		—		26.3		—		26.3
Valuation allowance on deferred taxes		—		—		93.6		—
Adjusted net income/(loss)	$	(41.2)	$	74.3	$	(20.1)	$	146.9

ENERPLUS 2020 Q2 REPORT 17

“Total debt net of cash” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. Total debt net of cash is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents.

“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) and is not a debt covenant.

“Adjusted payout ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate adjusted payout ratio as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow.


Calculation of Adjusted Payout Ratio	Three months ended June 30,				Six months ended June 30,
($ millions)	2020		2019		2020		2019
Dividends	$	6.7	$	7.0	$	13.3	$	14.2
Capital, office expenditures and line fill		41.0		209.3		206.5		376.4
Sub-total	$	47.7	$	216.3	$	219.8	$	390.6
Adjusted funds flow	$	70.0	$	186.0	$	183.2	$	354.8
Adjusted payout ratio (%)		68%		116%		120%		110%

“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under its bank credit facility and outstanding senior notes. Adjusted EBITDA is calculated on the trailing four quarters.


Reconciliation of Net Income/(Loss) to Adjusted EBITDA⁽¹⁾
($ millions)	June 30, 2020
Net income/(loss)	$	(970.4)
Add:
Goodwill impairment		653.9
Interest		32.8
Current and deferred tax expense/(recovery)		32.4
DD&A and asset impairment		794.5
Other non-cash charges⁽²⁾		3.9
Adjusted EBITDA	$	547.1

(1)	Balances above at June 30, 2020 include the six months ended June 30, 2020 and the third and fourth quarter of 2019.

(2)	Includes the change in fair value of commodity derivatives and equity swaps, non-cash SBC expense, non-cash G&A expense and unrealized foreign exchange gains/losses.

In addition, the Company uses certain financial measures within the “Liquidity and Capital Resources” section of this MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include “senior debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “senior debt to consolidated present value of total proved reserves” and “adjusted EBITDA to interest” and are used to determine the Company’s compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A.

INTERNAL CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as defined in Rule 13a - 15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada under National Instrument 52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at June 30, 2020, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal control over financial reporting during the period beginning on April 1, 2020 and ended June 30, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our current Annual Information Form (“AIF”), is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

18 ENERPLUS 2020 Q2 REPORT

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "ongoing", "may", "will", "project", "plans", “budget”, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: expected capital spending levels in 2020 and impact thereof on our production levels and land holdings; expected production volumes; expected operating strategy in 2020, including the proportion of Enerplus' production that may be curtailed and the effect of such actions on its properties, operations and financial position; the proportion of our anticipated oil and gas production that is hedged and the expected effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials, our commodity risk management program in 2020 and expected hedging gains; expectations regarding our realized oil and natural gas prices; expected operating, transportation and cash G&A costs; potential future non-cash PP&E impairments, as well as relevant factors that may affect such impairment; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with debt covenants under our bank credit facility and outstanding senior notes; Enerplus' costs reduction initiatives and the expected cost savings therefrom in 2020; and the amount of future cash dividends that we may pay to our shareholders.

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus 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 and/or low commodity price environment will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, 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; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to comply with our debt covenants; the availability of third party services; and the extent of our liabilities. In addition, our expected 2020 capital expenditures and operating strategy described in this MD&A is based on the rest of the year prices and exchange rate of: a WTI price of US$41.19/bbl, a NYMEX price of US$1.94/Mcf, and a USD/CDN exchange rate of 1.35. Enerplus believes 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. Current conditions, economic and otherwise, render assumptions, although reasonable when made, subject to greater uncertainty.

The forward-looking information included in this MD&A 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: continued instability, or further deterioration, in global economic and market environment, including from COVID-19; continued low commodity prices environment or further decline and/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; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; 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 identified in this MD&A, our Annual Information Form, our Annual MD&A and Form 40-F as at December 31, 2019).

The forward-looking information contained in this MD&A speak only as of the date of this MD&A. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.

ENERPLUS 2020 Q2 REPORT 19

STATEMENTS

Exhibit 99.2

Condensed Consolidated Balance Sheets


(CDN$ thousands) unaudited	Note	June 30, 2020		December 31, 2019
Assets
Current Assets
Cash and cash equivalents		$	6,177	$	151,649
Accounts receivable	4		121,395		176,119
Income tax receivable	14		29,116		27,770
Derivative financial assets	16		46,186		10,570
Other current assets			3,190		2,990
			206,064		369,098
Property, plant and equipment:
Oil and natural gas properties (full cost method)	5		1,230,072		1,547,362
Other capital assets, net	5		20,746		20,244
Property, plant and equipment			1,250,818		1,567,606
Right-of-use assets	10		39,149		48,729
Goodwill	6		—		194,015
Deferred income tax asset	14		367,270		372,502
Income tax receivable	14		—		13,852
Total Assets		$	1,863,301	$	2,565,802

Liabilities
Current liabilities
Accounts payable	7	$	244,929	$	291,540
Dividends payable			2,225		2,217
Current portion of long-term debt	8		110,780		105,998
Derivative financial liabilities	16		5,851		2,734
Current portion of lease liabilities	10		13,410		17,541
			377,195		420,030
Long-term debt	8		413,491		500,635
Asset retirement obligation	9		146,171		138,049
Lease liabilities	10		30,228		35,530
			589,890		674,214
Total Liabilities			967,085		1,094,244

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2020 – 223 million shares December 31, 2019 – 222 million shares	15		3,096,969		3,088,094
Paid-in capital			48,758		59,490
Accumulated deficit			(2,601,744)		(1,984,365)
Accumulated other comprehensive income/(loss)			352,233		308,339
			896,216		1,471,558
Total Liabilities & Shareholders' Equity		$	1,863,301	$	2,565,802

Commitments and Contingencies	17

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

ENERPLUS 2020 Q2 REPORT 1

Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)


		Three months ended				Six months ended
		June 30,				June 30,
(CDN$ thousands, except per share amounts) unaudited	Note	2020		2019		2020		2019
Revenues
Oil and natural gas sales, net of royalties	11	$	122,069	$	321,463	$	350,196	$	608,915
Commodity derivative instruments gain/(loss)	16		(10,895)		27,422		120,446		(57,445)
			111,174		348,885		470,642		551,470
Expenses
Operating			54,353		71,818		133,373		141,611
Transportation			34,006		36,803		69,335		68,094
Production taxes			7,687		21,442		23,131		36,057
General and administrative	12		13,494		15,680		32,679		37,390
Depletion, depreciation and accretion			79,885		88,315		175,077		164,226
Asset impairment	6		426,810		—		426,810		—
Goodwill impairment	6		202,767		—		202,767		—
Interest			7,051		8,693		15,962		17,086
Foreign exchange (gain)/loss	13		1,493		(12,251)		(4,144)		(24,277)
Other expense/(income)			6,301		(1,568)		6,072		(4,430)
			833,847		228,932		1,081,062		435,757
Income/(Loss) before taxes			(722,673)		119,953		(610,420)		115,713
Current income tax expense/(recovery)	14		(14,422)		(13,928)		(14,395)		(19,458)
Deferred income tax expense/(recovery)	14		(98,928)		48,797		10,422		30,929
Net Income/(Loss)		$	(609,323)	$	85,084	$	(606,447)	$	104,242

Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation			(57,284)		(34,208)		74,490		(70,564)
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt	3,16		19,466		—		(30,596)		—
Total Comprehensive Income/(Loss)		$	(647,141)	$	50,876	$	(562,553)	$	33,678

Net income/(Loss) per share
Basic	15	$	(2.74)	$	0.36	$	(2.73)	$	0.44
Diluted	15	$	(2.74)	$	0.36	$	(2.73)	$	0.43

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

2 ENERPLUS 2020 Q2 REPORT

Condensed Consolidated Statements of Changes in Shareholders’ Equity


		Three months ended				Six months ended
		June 30,				June 30,
(CDN$ thousands) unaudited	2020		2019		2020		2019
Share Capital
Balance, beginning of period	$	3,097,187	$	3,317,855	$	3,088,094	$	3,337,608
Purchase of common shares under Normal Course Issuer Bid		—		(92,264)		(4,731)		(116,423)
Share-based compensation – treasury settled		—		—		13,824		4,406
Cancellation of predecessor shares		(218)		—		(218)		—
Balance, end of period	$	3,096,969	$	3,225,591	$	3,096,969	$	3,225,591

Paid-in Capital
Balance, beginning of period	$	44,430	$	45,209	$	59,490	$	46,524
Share-based compensation – cash settled (tax withholding)		—		—		(7,232)		(4,952)
Share-based compensation – treasury settled		—		—		(13,824)		(4,406)
Share-based compensation – non-cash		4,328		4,263		10,324		12,306
Balance, end of period	$	48,758	$	49,472	$	48,758	$	49,472

Accumulated Deficit
Balance, beginning of period	$	(1,985,964)	$	(1,755,757)	$	(1,984,365)	$	(1,772,084)
Purchase of common shares under Normal Course Issuer Bid		—		21,708		2,195		26,039
Net income/(loss)		(609,323)		85,084		(606,447)		104,242
Cancellation of predecessor shares		218		—		218		—
Dividends declared ($0.01 per share)		(6,675)		(7,034)		(13,345)		(14,196)
Balance, end of period	$	(2,601,744)	$	(1,655,999)	$	(2,601,744)	$	(1,655,999)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of period	$	390,051	$	352,585	$	308,339	$	388,941
Unrealized gain/(loss) on foreign currency translation		(57,284)		(34,208)		74,490		(70,564)
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt		19,466		—		(30,596)		—
Balance, end of period	$	352,233	$	318,377	$	352,233	$	318,377
Total Shareholders’ Equity	$	896,216	$	1,937,441	$	896,216	$	1,937,441

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

ENERPLUS 2020 Q2 REPORT 3

Condensed Consolidated Statements of Cash Flows


		Three months ended				Six months ended
		June 30,				June 30,
(CDN$ thousands) unaudited	Note	2020		2019		2020		2019
Operating Activities
Net income/(loss)		$	(609,323)	$	85,084	$	(606,447)	$	104,242
Non-cash items add/(deduct):
Depletion, depreciation and accretion			79,885		88,315		175,077		164,226
Asset impairment	6		426,810		—		426,810		—
Goodwill impairment	6		202,767		—		202,767		—
Changes in fair value of derivative instruments	16		63,929		(28,353)		(32,499)		66,975
Deferred income tax expense/(recovery)	14		(98,928)		48,797		10,422		30,929
Foreign exchange (gain)/loss on debt and working capital	13,16		1,038		(16,498)		(1,377)		(33,602)
Share-based compensation and general and administrative	12,15		3,428		4,535		11,183		12,669
Translation of U.S. dollar cash held in Canada	13		391		4,158		(2,712)		9,354
Asset retirement obligation expenditures	9		(333)		(503)		(11,127)		(5,893)
Changes in non-cash operating working capital	18		20,896		51,456		41,202		(2,958)
Cash flow from/(used in) operating activities			90,560		236,991		213,299		345,942

Financing Activities
Bank credit facility	8		1,364		—		1,364		—
Senior notes	8		(114,010)		(59,429)		(114,010)		(59,429)
Purchase of common shares under Normal Course Issuer Bid	15		—		(70,556)		(2,536)		(90,384)
Share-based compensation – cash settled (tax withholding)	15		—		—		(7,232)		(4,952)
Dividends	15,18		(6,676)		(7,099)		(13,337)		(14,273)
Cash flow from/(used in) financing activities			(119,322)		(137,084)		(135,751)		(169,038)

Investing Activities
Capital and office expenditures	18		(104,111)		(168,282)		(233,453)		(280,077)
Property and land acquisitions			(3,416)		(1,911)		(5,672)		(4,892)
Property divestments			(63)		9,601		5,515		10,023
Cash flow from/(used in) investing activities			(107,590)		(160,592)		(233,610)		(274,946)
Effect of exchange rate changes on cash and cash equivalents			453		(5,780)		10,590		(12,754)
Change in cash and cash equivalents			(135,899)		(66,465)		(145,472)		(110,796)
Cash and cash equivalents, beginning of period			142,076		318,996		151,649		363,327
Cash and cash equivalents, end of period		$	6,177	$	252,531	$	6,177	$	252,531

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

4 ENERPLUS 2020 Q2 REPORT

NOTES

Notes to Condensed Consolidated Financial Statements

(unaudited)

1) REPORTING ENTITY

These interim Condensed Consolidated Financial Statements (“interim Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (“the Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

2) BASIS OF PREPARATION

Enerplus’ interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in the United States of America (“U.S. GAAP”) for the three and six months ended June 30, 2020 and the 2019 comparative periods. Certain information and notes normally included with the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with Enerplus’ annual audited Consolidated Financial Statements as of December 31, 2019.

These unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of the Company as at and for the periods presented.

i.Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), impairment of property, plant and equipment, asset retirement obligations, income taxes, ability to realize deferred income tax assets, impairment assessments of goodwill and the fair value of derivative instruments. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions.

In early March 2020, the World Health Organization declared the coronavirus (“COVID-19”) outbreak a pandemic. Responses to the spread of COVID-19 have resulted in a challenging economic climate, with more volatile commodity prices and foreign exchange rates, and a decline in long-term interest rates. Although global economies began to recover during the second quarter, markets remain volatile as the timing of full economic recovery remains uncertain. It is difficult to reliably estimate the length or severity of these developments and their financial impact. The impacts of the economic downturn to Enerplus have been considered in management’s estimates described above at June 30, 2020; however, estimates made during this period of extreme volatility are subject to a higher level of uncertainty and as a result, there may be a further prospective material impact in future periods.

3) ACCOUNTING POLICY CHANGES

Recently adopted accounting standards

a)Hedge Accounting

Effective January 1, 2020, the Company adopted hedge accounting in order to mitigate the foreign currency exposure related to its net investment in its U.S. subsidiary. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. To be accounted for as a hedge, the U.S. dollar denominated debt must be designated an effective hedge, both at inception and on an ongoing basis. The required hedge documentation defines the relationship between the U.S. dollar denominated debt and the net investment in the U.S. subsidiary, as well as the Company’s risk management objective and strategy for undertaking the hedging transaction. The Company formally assesses, both at inception and on an ongoing basis, whether the changes in fair value of the U.S. dollar denominated debt are highly effective in offsetting changes in fair value of the net investment in the U.S. subsidiary. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited to the translation gain or loss on the net investment.

ENERPLUS 2020 Q2 REPORT 5

A reduction in the fair value of the net investment in the U.S. subsidiary or increase in the U.S. dollar denominated debt may result in a portion of the hedge becoming ineffective. If the hedging relationship ceases to be effective or is terminated, hedge accounting is not applied and subsequent gains or losses are recorded through net income/(loss).

b)Impairment of Financial Instruments

Enerplus adopted ASC 326 – Financial Instruments – Credit Losses effective January 1, 2020 using the modified retrospective method, with the cumulative effect on comparative periods reflected as an adjustment to retained earnings, if applicable. The adoption of the standard had no impact on the interim Consolidated Financial Statements, with the exception of the revised disclosures which are detailed in Note 16. As a result of this adoption, Enerplus has revised its accounting policy for financial instruments as follows:

The Company has adopted the current expected credit loss model for its accounts receivable, which requires the use of a lifetime expected loss provision. In making an assessment as to whether financial assets are credit-impaired, the Company considers: (i) historically realized bad debts; (ii) a counterparty’s present financial condition and whether a counterparty has breached certain contracts; (iii) the probability that a counterparty will enter bankruptcy or other financial reorganization; (iv) changes in economic conditions that correlate to increased levels of default; and (v) the term to maturity of the specified receivable. The carrying amounts of receivables are reduced by the amount of the expected credit loss through an allowance account and losses are recognized within general and administrative expense in the Consolidated Statement of Income/(Loss). If the Company subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account.

c)Goodwill

Enerplus adopted ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) effective January 1, 2020 using the prospective method. The amended standard simplifies the goodwill impairment test. As a result of this adoption, Enerplus has revised its accounting policy for goodwill as follows:

4) ACCOUNTS RECEIVABLE


($ thousands)	June 30, 2020			December 31, 2019
Accrued revenue	$	93,362	$		142,048
Accounts receivable – trade		31,744			37,736
Allowance for doubtful accounts		(3,711)			(3,665)
Total accounts receivable, net of allowance for doubtful accounts	$	121,395	$		176,119

5) PROPERTY, PLANT AND EQUIPMENT (“PP&E”)


			Accumulated Depletion,
As of June 30, 2020			Depreciation, and
($ thousands)		Cost	Impairment			Net Book Value
Oil and natural gas properties⁽¹⁾	$	15,631,936	$	(14,401,864)	$	1,230,072
Other capital assets		127,964		(107,218)		20,746
Total PP&E	$	15,759,900	$	(14,509,082)	$	1,250,818


			Accumulated Depletion,
As of December 31, 2019			Depreciation, and
($ thousands)		Cost	Impairment			Net Book Value
Oil and natural gas properties⁽¹⁾	$	15,088,724	$	(13,541,362)	$	1,547,362
Other capital assets		125,265		(105,021)		20,244
Total PP&E	$	15,213,989	$	(13,646,383)	$	1,567,606

(1)	All of the Company’s unproved properties are included in the full cost pool.

6 ENERPLUS 2020 Q2 REPORT

6) IMPAIRMENT

a)	Impairment of PP&E


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Oil and natural gas properties:
Canada cost centre	$	77,500	$	—	$	77,500	$	—
U.S. cost centre		349,310		—		349,310		—
Impairment expense	$	426,810	$	—	$	426,810	$	—

The PP&E impairments for the three and six months ended June 30, 2020 were due to lower twelve month average trailing crude oil and natural gas prices. There was no PP&E impairment recorded for the six months ended June 30, 2019. If commodity prices remain at current levels, the twelve month average trailing prices will decline further, impacting Enerplus’ ceiling value and resulting in an increased risk of future PP&E impairment.

The following table outlines the twelve month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling tests from June 30, 2019 through June 30, 2020:


		WTI Crude Oil		Edm Light Crude		U.S. Henry Hub	Exchange Rate
Period		US$/bbl		CDN$/bbl		Gas US$/Mcf	US$/CDN$
Q2 2020	$	47.37	$	54.94	$	2.08	1.34
Q1 2020		55.96		66.42		2.30	1.33
Q4 2019		55.85		66.73		2.58	1.33
Q3 2019		57.77		62.79		2.83	1.33
Q2 2019		61.38		66.07		3.02	1.32

b)	Impairment of Goodwill

Enerplus recorded goodwill impairment of $202.8 million related to its U.S. reporting unit for the period ended June 30, 2020 (December 31, 2019 - $451.1 million for the Canadian reporting unit). The impairment was a result of the ongoing deteriorating macroeconomic conditions and low commodity prices due to the COVID-19 pandemic, which resulted in a reduction in the fair value of the U.S. reporting unit. The estimated fair value of the U.S. reporting unit for the goodwill impairment test was based on its reserve values at forecast prices and costs. At June 30, 2020, there was no goodwill remaining on the Company’s Condensed Consolidated Balance Sheet.

7) ACCOUNTS PAYABLE


($ thousands)	June 30, 2020		December 31, 2019
Accrued payables	$	95,600	$	105,928
Accounts payable – trade		149,329		185,612
Total accounts payable	$	244,929	$	291,540

8) DEBT


($ thousands)	June 30, 2020		December 31, 2019
Current:
Senior notes	$	110,780	$	105,998
Long-term:
Bank credit facility		1,052		—
Senior notes		412,439		500,635
Total debt	$	524,271	$	606,633

ENERPLUS 2020 Q2 REPORT 7

The terms and rates of the Company’s outstanding senior notes are provided below:

Original

Remaining

CDN$ Carrying

Interest

Coupon

Principal

Value

Issue Date

Payment Dates

Principal Repayment

Rate

($ thousands)

September 3, 2014

March 3 and Sept 3

5 equal annual installments beginning September 3, 2022

3.79%

US$200,000

US$105,000

142,548

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

27,152

May 15, 2012

May 15 and Nov 15

4 equal annual installments beginning May 15, 2021

4.40%

US$355,000

US$238,400

323,652

June 18, 2009

June 18 and Dec 18

Final installment on June 18, 2021

7.97%

US$225,000

US$22,000

29,867

Total carrying value

523,219

During the three and six months ended June 30, 2020, Enerplus made its fourth US$22 million principal repayment on its 2009 senior notes and its first US$59.6 million principal repayment on its 2012 senior notes. During the three and six months ended June 30, 2019, Enerplus made its third US$22 million principal repayment on its 2009 senior notes and a $30 million bullet repayment on its 2012 senior notes.

9) ASSET RETIREMENT OBLIGATION


($ thousands)	June 30, 2020		December 31, 2019
Balance, beginning of year	$	138,049	$	126,112
Change in estimates		14,632		23,362
Property acquisitions and development activity		2,001		2,068
Divestments		(1,031)		(2,760)
Settlements		(11,127)		(16,715)
Accretion expense		3,647		5,982
Balance, end of period	$	146,171	$	138,049

Enerplus has estimated the present value of its asset retirement obligation to be $146.2 million at June 30, 2020 based on a total undiscounted liability of $356.3 million (December 31, 2019 – $138.0 million and $344.7 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk-free rate of 5.35% (December 31, 2019 –5.50%).

10) LEASES

The Company incurs lease payments related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Condensed Consolidated Balance Sheet. Such items are charged to operating expenses and general and administrative expenses in the Condensed Consolidated Statement of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with other U.S. GAAP.


($ thousands)	June 30, 2020		December 31, 2019
Assets
Operating right-of-use assets	$	39,149	$	48,729

Liabilities
Current operating lease liabilities	$	13,410	$	17,541
Non-current operating lease liabilities		30,228		35,530

Weighted average remaining lease term (years)
Operating leases		4.2		4.3

Weighted average discount rate
Operating leases		4.1%		4.1%

8 ENERPLUS 2020 Q2 REPORT

The components of lease expense for the three and six months ended June 30, 2020 are as follows:


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Operating lease cost	$	4,182	$	5,097	$	9,315	$	9,691
Variable lease cost		190		185		507		469
Short-term lease cost		1,893		3,811		7,177		7,932
Sublease income		(251)		(256)		(544)		(500)
Total	$	6,014	$	8,837	$	16,455	$	17,592

Maturities of lease liabilities, all of which are classified as operating leases at June 30, 2020 are as follows:


($ thousands)	Operating Leases
2020	$	7,517
2021		14,754
2022		8,079
2023		6,914
2024		6,263
After 2025		4,158
Total lease payments	$	47,685
Less imputed interest		(4,047)
Total discounted lease payments	$	43,638
Current portion of lease liabilities	$	13,410
Non-current portion of lease liabilities	$	30,228

Supplemental information related to leases is as follows:


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	3,913	$	4,758	$	8,841	$	9,264
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	(3,473)	$	1,105	$	(2,950)	$	19,967

11) OIL AND NATURAL GAS SALES


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Oil and natural gas sales	$	155,259	$	403,206	$	440,857	$	759,582
Royalties⁽¹⁾		(33,190)		(81,743)		(90,661)		(150,667)
Oil and natural gas sales, net of royalties	$	122,069	$	321,463	$	350,196	$	608,915

(1)	Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

Oil and natural gas revenue by country and by product for the three and six months ended June 30, 2020 and 2019 are as follows:


Three months ended June 30, 2020		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	13,027	$	9,720	$	2,122	$	565	$	620
United States		109,042		84,063		25,969		(1,006)		16
Total	$	122,069	$	93,783	$	28,091	$	(441)	$	636


Three months ended June 30, 2019		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	47,378	$	41,386	$	3,703	$	1,582	$	707
United States		274,085		217,830		51,766		4,489		—
Total	$	321,463	$	259,216	$	55,469	$	6,071	$	707

(1)	Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

(2)	U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)	Includes third party processing income.

ENERPLUS 2020 Q2 REPORT 9


Six months ended June 30, 2020		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	40,120	$	31,710	$	5,510	$	1,659	$	1,241
United States		310,076		243,827		63,435		2,744		70
Total	$	350,196	$	275,537	$	68,945	$	4,403	$	1,311


Six months ended June 30, 2019		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	100,276	$	80,805	$	14,071	$	4,068	$	1,332
United States		508,639		375,669		124,922		8,048		—
Total	$	608,915	$	456,474	$	138,993	$	12,116	$	1,332

(1)	Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

(2)	U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)	Includes third party processing income.

12) GENERAL AND ADMINISTRATIVE EXPENSE


	Three months ended June 30,					Six months ended June 30,
($ thousands)	2020		2019		2020			2019
General and administrative expense	$	9,231	$	11,796	$		21,566	$	24,227
Share-based compensation expense		4,263		3,884			11,113		13,163
General and administrative expense⁽¹⁾	$	13,494	$	15,680	$		32,679	$	37,390

(1)	Includes cash and non-cash amounts.

13) FOREIGN EXCHANGE


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Realized:
Foreign exchange (gain)/loss	$	64	$	89	$	(55)	$	(29)
Translation of U.S. dollar cash held in Canada (gain)/loss		391		4,158		(2,712)		9,354
Unrealized:
Translation of U.S. dollar debt and working capital (gain)/loss		1,038		(16,498)		(1,377)		(33,602)
Foreign exchange (gain)/loss	$	1,493	$	(12,251)	$	(4,144)	$	(24,277)

Effective January 1, 2020, the Company elected to apply net investment hedge accounting. Any unrealized foreign exchange gain or loss recorded on certain U.S. dollar denominated debt held in Canada after adoption has been reflected in Other Comprehensive Income/(Loss) on the Consolidated Statements of Income/(Loss). See Note 3 for further details.

14) INCOME TAXES


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Current tax
Canada	$	—	$	(13,941)	$	—	$	(13,941)
United States		(14,422)		13		(14,395)		(5,517)
Current tax expense/(recovery)		(14,422)		(13,928)		(14,395)		(19,458)
Deferred tax
Canada	$	(25,629)	$	34,808	$	98,852	$	5,249
United States		(73,299)		13,989		(88,430)		25,680
Deferred tax expense/(recovery)		(98,928)		48,797		10,422		30,929
Income tax expense/(recovery)	$	(113,350)	$	34,869	$	(3,973)	$	11,471

The difference between the expected income taxes based on the statutory income tax rate and the effective income taxes for the current and prior period is impacted by the following: expected annual earnings, recognition or reversal of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, non-taxable portions of capital gains and losses, and share-based compensation.

During the three months ended June 30, 2020, Enerplus recorded an additional current tax recovery of $14.4 million for the final year of U.S. Alternative Minimum Tax (“AMT”) refund.

10 ENERPLUS 2020 Q2 REPORT

At June 30, 2020, $28.9 million of the current income tax receivable related to remaining U.S. AMT refunds (December 31, 2019 - $27.8 million).

15) SHAREHOLDERS’ EQUITY

a) Share Capital


	Six months ended			Year ended
Authorized unlimited number of common shares issued:	June 30, 2020			December 31, 2019
(thousands)	Shares		Amount	Shares		Amount
Balance, beginning of year	221,744	$	3,088,094	239,411	$	3,337,608

Issued/(Purchased) for cash:
Purchase of common shares under Normal Course Issuer Bid	(340)		(4,731)	(18,231)		(253,920)

Non-cash:
Share-based compensation – treasury settled⁽¹⁾	1,160		13,824	564		4,406
Cancellation of predecessor shares	(16)		(218)	—		—
Balance, end of period	222,548	$	3,096,969	221,744	$	3,088,094

(1)	The amount of shares issued on LTI settlement is net of employee withholding taxes.

Dividends declared to shareholders for the three and six months ended June 30, 2020 were $6.7 million and $13.3 million, respectively (2019 – $7.0 million and $14.2 million, respectively).

Enerplus’ Normal Course Issuer Bid (“NCIB”) expired on March 25, 2020. The Company chose not to renew the NCIB upon expiry in order to conserve capital and preserve its liquidity. All repurchases were made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess allocated to accumulated deficit.

During the six months ended June 30, 2020, the Company repurchased 340,434 common shares under the NCIB at an average price of $7.44 per share, for total consideration of $2.5 million. Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit.

During the six months ended June 30, 2019, the Company repurchased 8,358,821 common shares under the previous NCIB at an average price of $10.80 per share, for total consideration of $90.4 million. Of the amount paid, $116.4 million was charged to share capital and $26.0 million was credited to accumulated deficit.

b) Share-based Compensation

The following table summarizes Enerplus’ share-based compensation expense, which is included in General and Administrative expense on the Condensed Consolidated Statements of Income/(Loss):


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Cash:
Long-term incentive plans (recovery)/expense	$	1,186	$	(626)	$	(1,561)	$	711
Non-cash:
Long-term incentive plans		3,550		4,263		11,239		12,306
Equity swap (gain)/loss		(473)		247		1,435		146
Share-based compensation expense	$	4,263	$	3,884	$	11,113	$	13,163

ENERPLUS 2020 Q2 REPORT 11

i) Long-term Incentive (“LTI”) Plans

The following table summarizes the Performance Share Unit (“PSU”), Restricted Share Unit (“RSU”) and Director Deferred Share Unit (“DSU”) and Director RSU (“DRSU”) activity for the six months ended June 30, 2020:


	Cash-settled LTI plans	Equity-settled LTI plans		Total
(thousands of units)	Director Plans	PSU⁽¹⁾	RSU
Balance, beginning of year	422	2,139	1,531	4,092
Granted	128	1,154	1,103	2,385
Vested	—	(652)	(741)	(1,393)
Forfeited	—	(88)	(62)	(150)
Balance, end of period	550	2,553	1,831	4,934

(1)	Based on underlying awards before any effect of the performance multiplier.

Cash-settled LTI Plans

For the three and six months ended June 30, 2020, the Company recorded a cash share-based compensation expense of $1.2 million and recovery of $1.6 million, respectively (June 30, 2019 – recovery of $0.6 million and expense of $0.7 million, respectively).

As of June 30, 2020, a liability of $2.1 million (December 31, 2019 – $3.9 million) with respect to the Director DSU and DRSU plans has been recorded to Accounts Payable on the Condensed Consolidated Balance Sheets.

Equity-settled LTI Plans

The following table summarizes the cumulative share-based compensation expense recognized to-date, which is recorded to Paid-in Capital on the Condensed Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.


At June 30, 2020 ($ thousands, except for years)	PSU⁽¹⁾		RSU		Total
Cumulative recognized share-based compensation expense	$	20,598	$	9,593	$	30,191
Unrecognized share-based compensation expense		13,936		9,762		23,698
Fair value	$	34,534	$	19,355	$	53,889
Weighted-average remaining contractual term (years)		1.9		1.6

(1)	Includes estimated performance multipliers.

For the six months ended June 30, 2020, $7.2 million (2019 – $5.0 million) in cash withholding taxes were paid on the PSU and RSU settlements.

ii) Stock Option Plan

At June 30, 2020 all stock options are fully vested and any related non-cash share-based compensation expense has been fully recognized. All remaining outstanding stock options expired in March 2020.

c) Basic and Diluted Net Income/(Loss) Per Share

Net income/(loss) per share has been determined as follows:


	Three months ended June 30,				Six months ended June 30,
(thousands, except per share amounts)	2020		2019		2020		2019
Net income/(loss)	$	(609,323)	$	85,084	$	(606,447)	$	104,242

Weighted average shares outstanding – Basic		222,557		235,490		222,457		237,197
Dilutive impact of share-based compensation⁽¹⁾		—		2,699		—		2,750
Weighted average shares outstanding – Diluted		222,557		238,189		222,457		239,947
Net income/(loss) per share
Basic	$	(2.74)	$	0.36	$	(2.73)	$	0.44
Diluted	$	(2.74)	$	0.36	$	(2.73)	$	0.43

(1)	For the three and six months ended June 30, 2020, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.

12 ENERPLUS 2020 Q2 REPORT

16) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At June 30, 2020, the carrying value of cash, accounts receivable, accounts payable, and dividends payable approximated their fair value due to the short-term maturity of the instruments.

At June 30, 2020, the senior notes had a carrying value of $523.2 million and a fair value of $515.7 million (December 31, 2019 – $606.6 million and $613.8 million, respectively).

The fair value of derivative contracts and senior notes are considered level 2 fair value measurements. There were no transfers between fair value hierarchy levels during the period.

b) Derivative Financial Instruments

The derivative financial assets and liabilities on the Condensed Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

The following table summarizes the change in fair value for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,				Six months ended June 30,				Income Statement
Gain/(Loss) ($ thousands)	2020		2019		2020		2019		Presentation
Equity Swaps	$	473	$	(247)	$	(1,435)		(146)	G&A expense
Commodity Derivative Instruments:
Oil		(64,402)		23,617		33,934		(63,312)	Commodity derivative
Gas		—		4,983		—		(3,517)	instruments
Total	$	(63,929)	$	28,353	$	32,499	$	(66,975)

The following table summarizes the effects of Enerplus’ commodity derivative instruments on the Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss):


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Change in fair value gain/(loss)	$	(64,402)	$	28,600	$	33,934	$	(66,829)
Net realized cash gain/(loss)		53,507		(1,178)		86,512		9,384
Commodity derivative instruments gain/(loss)	$	(10,895)	$	27,422	$	120,446	$	(57,445)

The following table summarizes the fair values of derivative financial instruments at the respective period ends:


	June 30, 2020				December 31, 2019
	Assets		Liabilities		Assets		Liabilities
($ thousands)	Current		Current		Current		Current
Equity Swaps	$	—	$	3,652	$	—	$	2,217
Commodity Derivative Instruments:
Oil		46,186		2,199		10,570		517
Total	$	46,186	$	5,851	$	10,570	$	2,734

c) Risk Management

i) Market Risk

Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.

Commodity Price Risk:

Enerplus manages a portion of commodity price risk through a combination of financial derivatives and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes, net of royalties and production taxes.

ENERPLUS 2020 Q2 REPORT 13

The following tables summarize the Company’s price risk management positions at August 6, 2020:

Crude Oil Instruments:


Instrument Type⁽¹⁾⁽²⁾	bbls/day	US$/bbl

Jul 1, 2020 – Sep 30, 2020
WTI Swap	7,000	36.02
WTI Purchased Put	21,000	57.20
WTI Sold Put	21,000	47.14
WTI Sold Call	5,000	65.00
WTI – Brent Swap (Purchase)	4,400	(8.03)
WTI – Brent Swap (Sale)	4,400	(3.62)

Oct 1, 2020 – Dec 31, 2020
WTI Purchased Put	21,000	57.20
WTI Sold Put	21,000	47.14
WTI Sold Call	5,000	65.00
WTI – Brent Swap (Purchase)	4,400	(8.03)
WTI – Brent Swap (Sale)	4,400	(3.62)

Jan 1, 2021 - Jun 30, 2021
WTI Purchased Put	6,000	40.00
WTI Sold Put	6,000	32.00
WTI Sold Call	6,000	50.00

(1)	Transactions with a common term have been aggregated and presented at a weighted average price/bbl before premiums.

(2)	The total average deferred premium on outstanding hedges is US$1.75/bbl from July 1, 2020 to December 31, 2020 and US$0.03/bbl from January 1, 2021 to June 30, 2021.

Enerplus has fixed physical differential sales agreements for approximately 16,000 bbls/day in North Dakota at an estimated price of approximately US$6.00/bbl below WTI for the remainder of 2020.

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At June 30, 2020, Enerplus did not have any foreign exchange derivatives outstanding.

Enerplus may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited to the translation gain or loss on the net investment. At June 30, 2020, Enerplus designated all of its US$385.4 million senior notes as a hedge of the Company’s net investment in its U.S. subsidiary. For the three and six months ended June 30, 2020, Enerplus recorded a $19.5 million gain and $30.6 million loss, net of tax of nil, respectively, on its net investment hedge.

Interest Rate Risk:

At June 30, 2020, approximately all of Enerplus’ debt was based on fixed interest rates and Enerplus had no interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 15. Enerplus has entered into various equity swaps maturing in 2020 that effectively fix the future settlement cost on a portion of its cash settled LTI plans.

ii) Credit Risk

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables. Enerplus has appropriate policies and procedures in place to manage its credit risk; however, given the recent rapid decline in commodity prices, Enerplus is subject to an increased risk of financial loss due to non-performance or insolvency of its counterparties.

Enerplus mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining

14 ENERPLUS 2020 Q2 REPORT

financial assurances such as letters of credit, parental guarantees or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At June 30, 2020, approximately 85% of Enerplus’ marketing receivables were with companies considered investment grade.

Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts of future payments or seeking other remedies including legal action. Enerplus’ allowance for doubtful accounts balance at June 30, 2020 was $3.7 million (December 31, 2019 – $3.7 million).

iii) Liquidity Risk & Capital Management

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt, net of cash and cash equivalents and share capital. Enerplus’ objective is to provide adequate short and long term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities.

Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, and acquisition and divestment activity.

At June 30, 2020, the Company was in full compliance with all covenants under the bank credit facility and outstanding senior notes. Enerplus expects to manage its business within these financial ratios during 2020; however, current oil and gas prices have created a significant level of uncertainty which may challenge this expectation. If the Company exceeds or anticipates exceeding its covenants, the Company may be required to repay, refinance or renegotiate the terms of the debt.

17) COMMITMENTS AND CONTINGENCIES

As of the date of this report, there were no material changes to Enerplus’ contractual obligations and commitments outside the ordinary course of business as reported in the Company’s annual audited Consolidated Financial Statements as of December 31, 2019.

Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded.

18) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Accounts receivable	$	(13,557)	$	37,580	$	67,259	$	23,401
Other assets		207		4,891		(200)		1,864
Accounts payable		34,246		8,985		(25,857)		(28,223)
	$	20,896	$	51,456	$	41,202	$	(2,958)

b) Changes in Other Non-Cash Working Capital


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Non-cash financing activities⁽¹⁾	$	(1)	$	(65)	$	8	$	(77)
Non-cash investing activities⁽²⁾		(63,094)		41,039		(26,899)		91,140

(1)	Relates to changes in dividends payable and included in dividends on the Condensed Consolidated Statements of Cash Flows.

(2)	Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Condensed Consolidated Statements of Cash Flows.

c) Other


	Three months ended June 30,				Six months ended June 30,
($ thousands)	2020		2019		2020		2019
Income taxes paid/(received)	$	71	$	(57,663)	$	(30,097)	$	(57,599)
Interest paid		12,966		14,390		16,253		17,649

ENERPLUS 2020 Q2 REPORT 15

16 ENERPLUS 2020 Q2 REPORT

Exhibit 99.3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Ian C. Dundas, President and Chief Executive Officer of Enerplus Corporation, certify the following:

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended June 30, 2020.

No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

Responsibility: The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1	Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

5.2	ICFR — material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2020 and ended on June 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 7, 2020


/s/ Ian C. Dundas
Ian C. Dundas President and Chief Executive Officer Enerplus Corporation

Exhibit 99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Jodine J. Jenson Labrie, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended June 30, 2020.

5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

(b)

5.1	Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by The Committee of Sponsoring Organizations of the Treadway Commission.

5.2	ICFR — material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2020 and ended on June 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 7, 2020