Report of Foreign Issuer (6-k)

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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, 2016

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 o Form 40-F ý

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 o No ý

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 o No ý

Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the securities Exchange Act of 1934.

Yes o No ý

EXHIBIT INDEX

EXHIBIT 99.1 — Enerplus Second Quarter Report for the Period Ending June 30, 2016

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 5, 2016

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EXHIBIT INDEX
SIGNATURE

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Exhibit 99.1

Selected Financial Results

SELECTED FINANCIAL RESULTS	Three months ended June 30,						Six months ended June 30,
		2016			2015			2016			2015

Financial (000's)
Funds Flow(4)	$	76,047		$	160,436		$	117,774		$	269,600
Dividends to Shareholders		6,547			30,935			21,011			78,294
Net Income/(Loss)		(168,554	)		(312,544	)		(342,220	)		(605,750	)
Debt Outstanding – net of cash		674,147			1,120,680			674,147			1,120,680
Capital Spending		48,120			147,979			91,396			314,989
Property and Land Acquisitions		343			(1,011	)		3,897			(1,248	)
Property Divestments		92,735			187,801			280,503			191,513
Debt to Funds Flow Ratio(4)		2.0x			1.6x			2.0x			1.6x
Financial per Weighted Average Shares Outstanding
Net Income/(Loss)	$	(0.77	)	$	(1.52	)	$	(1.61	)	$	(2.94	)
Weighted Average Number of Shares Outstanding (000's)		218,128			206,208			212,420			206,028
Selected Financial Results per BOE(1)(2)
Oil & Natural Gas Sales(3)	$	24.96		$	30.53		$	21.99		$	28.78
Royalties and Production Taxes		(5.51	)		(6.23	)		(4.72	)		(5.88	)
Commodity Derivative Instruments		2.53			7.47			3.51			8.48
Cash Operating Expenses		(7.20	)		(8.12	)		(7.67	)		(8.81	)
Transportation Costs		(2.87	)		(2.87	)		(2.88	)		(2.89	)
General and Administrative Expenses		(1.71	)		(2.03	)		(1.89	)		(2.19	)
Cash Share-Based Compensation		(0.09	)		0.13			(0.09	)		(0.32	)
Interest, Foreign Exchange and Other Expenses		(1.21	)		(2.48	)		(1.51	)		(2.87	)
Current Income Tax Recovery		0.02			0.01			0.02			–

Funds Flow(4)	$	8.92		$	16.41		$	6.76		$	14.30

SELECTED OPERATING RESULTS	Three months ended June 30,				Six months ended June 30,
		2016		2015		2016		2015

Average Daily Production(2)
Crude Oil (bbls/day)		39,079		41,122		39,294		40,243
Natural Gas Liquids (bbls/day)		4,829		5,145		5,161		4,444
Natural Gas (Mcf/day)		298,503		366,971		307,827		356,836
Total (BOE/day)		93,659		107,429		95,759		104,160
% Crude Oil and Natural Gas Liquids		47%		43%		46%		43%
Average Selling Price(2)(3)
Crude Oil (per bbl)	$	46.48	$	58.26	$	39.00	$	51.35
Natural Gas Liquids (per bbl)		15.67		20.88		13.37		21.55
Natural Gas (per Mcf)		1.49		2.09		1.64		2.32
Net Wells Drilled		5		8		17		36

(1): Non-cash amounts have been excluded.
(2): Based on Company interest production volumes. See "Basis of Presentation" section in the following MD&A.
(3): Before transportation costs, royalties and commodity derivative instruments.
(4): These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures" section in the following MD&A.

ENERPLUS 2016 Q2 REPORT 1

	Three months ended June 30,				Six months ended June 30,
Average Benchmark Pricing		2016		2015		2016		2015

WTI crude oil (US$/bbl)	$	45.59	$	57.94	$	39.52	$	53.29
AECO natural gas – monthly index (CDN$/Mcf)		1.25		2.67		1.68		2.81
AECO natural gas – daily index (CDN$/Mcf)		1.40		2.64		1.62		2.70
NYMEX natural gas – last day (US$/Mcf)		1.95		2.64		2.02		2.81
USD/CDN average exchange rate		1.29		1.23		1.33		1.24

Share Trading Summary For the three months ended June 30, 2016		CDN(1) – ERF (CDN$)		U.S.(2) – ERF (US$)

High	$	8.78	$	6.94
Low	$	4.68	$	3.55
Close	$	8.51	$	6.57

(1): TSX and other Canadian trading data combined.
(2): NYSE and other U.S. trading data combined.

2016 Dividends per Share Payment Month		CDN$		US$(1)

First Quarter Total	$	0.09	$	0.06

April	$	0.01	$	0.01
May		0.01		0.01
June		0.01		0.01

Second Quarter Total	$	0.03	$	0.03

Total Year to Date	$	0.12	$	0.09

(1): CDN$ dividends converted at the relevant foreign exchange rate on the payment date.

2 ENERPLUS 2016 Q2 REPORT

NEWS RELEASE

"We have significantly strengthened our balance sheet having reduced our debt, net of cash, by 45% since year-end 2015. In addition, we continue to drive costs lower as we position our company to deliver profitable growth in a lower commodity price environment," stated Ian C. Dundas, President & CEO. "Enerplus continues to perform at a high level operationally, and with our lower cost structure and improved financial strength we are modestly increasing our 2016 capital program in North Dakota as we position the company for growth in 2017."

Key Takeaways:

•: Production averaged 93,659 BOE per day during the quarter, including 43,908 barrels per day of crude oil and natural gas liquids. Annual average 2016 production is tracking the higher-end of Enerplus' guidance range of 90,000 – 94,000 BOE per day, despite the divestment of approximately 2,300 BOE per day at the end of the second quarter, largely due to strong Marcellus production. As a result, Enerplus is updating its 2016 average production guidance to 92,000 – 94,000 BOE per day. Crude oil and natural gas liquids production guidance remains unchanged at 43,000 – 45,000 barrels per day.
•: Enerplus has significantly strengthened its balance sheet in 2016. The receipt of divestment proceeds of $280.5 million year to date and net equity financing proceeds of $220.4 million, have helped reduce the Company's total debt net of cash by 45% since December 31, 2015. At June 30, 2016, Enerplus had $723.3 million of senior notes outstanding and $49.2 million in cash and the Company's $800 million bank credit facility was undrawn. At June 30, 2016, the Company's senior debt to adjusted EBITDA ratio was 1.2 times and debt to funds flow ratio was 2.0 times.
•: Enerplus continued to deliver significant cost savings during the second quarter including a reduction in cash costs comprising operating, transportation, G&A and interest of $1.68 per BOE compared to the same period in 2015.
•: Operating costs were $7.10 per BOE in the quarter, 10% lower than the same period in 2015 and below the Company's annual guidance of $8.50 per BOE as a result of continued cost reductions and the divestment of higher operating cost properties. Cash G&A expenses were $1.71 per BOE in the second quarter, 16% lower than the same period in 2015 and below the Company's annual guidance of $2.00 per BOE primarily due to a reduction in staffing levels. Based on this performance, Enerplus is reducing its 2016 guidance for operating expenses to $7.90 per BOE and cash G&A expenses to $1.95 per BOE.
•: Enerplus recorded a net loss of $168.6 million or ($0.77) per share in the second quarter, which is attributable to non-cash items including an impairment charge and a deferred tax asset valuation allowance as a result of the continued decline in the twelve month trailing average commodity prices.
•: Enerplus generated second quarter funds flow of $76.0 million, an increase of 82% from the previous quarter. The increased funds flow was driven by higher crude oil prices, improved commodity price differentials and lower cash costs.
•: Enerplus' realized pricing differentials in the Bakken and Marcellus have meaningfully improved over the past year. Although in part this is due to lower benchmark prices, improvements in the supply-demand balance in each basin have also contributed to the tighter differentials. Compared to the same period in 2015, Enerplus' second quarter realized Bakken differential narrowed by US$1.07 per barrel to US$8.23 per barrel below WTI, and Enerplus' second quarter realized Marcellus differential narrowed by US$0.63 per Mcf averaging US$0.76 per Mcf below NYMEX.
•: Capital spending in the second quarter was $48.1 million of which $30.4 million was directed to North Dakota. As a result of Enerplus' stronger financial position and lower cost structure, which is driving margin improvement, the Company is increasing its 2016 capital spending guidance to $215 million from $200 million to add three gross completions and pre-order facilities equipment in North Dakota during the latter part of the year for the 2017 program. The incremental expenditure will allow Enerplus to further test well downspacing in Fort Berthold, and is expected to add approximately 1,000 BOE per day to Enerplus' fourth quarter production volumes and better position the Company for growth in 2017. Enerplus continues to expect its 2016 capital and dividend commitments to be fully funded through internally generated cash flow at current forward strip commodity prices.

ENERPLUS 2016 Q2 REPORT 3

Asset Activity

North Dakota production averaged 28,800 BOE per day during the second quarter, largely flat from the previous quarter and up 6% from the same period in 2015. Enerplus continues to operate one drilling rig at Fort Berthold with capital spending in the quarter totaling $30.4 million resulting in 4.6 net wells drilled and 7.2 net wells on-stream. Well costs continue to trend down as a result of improvements in drilling time and ongoing completions optimization. Enerplus' average cost for a two-mile lateral well in the second quarter was US$7.8 million including drilling, completion, tie-in and facilities costs, 26% lower than the Company's 2015 average. Initial 30-day production rates from operated wells brought on-stream in the second quarter averaged approximately 1,450 BOE per day. At the end of the quarter, Enerplus had approximately 8 net drilled uncompleted wells in Fort Berthold.

Marcellus production averaged 195 MMcf per day during the second quarter, a modest increase from the first quarter of 2016. Capital spending in the Marcellus was $9.3 million in the quarter delivering 0.3 net wells drilled and 1.8 net wells on-stream. The production increase over the previous quarter was due to strong well performance. Enerplus participated in 7 gross on-stream wells in the second quarter with initial 30-day production rates that averaged 15.8 MMcf per day and an average lateral length of 6,400 ft. Enerplus continues to plan for limited activity levels in the Marcellus for the remainder of 2016.

Production from the Canadian waterflood assets averaged 16,560 BOE per day during the second quarter of 2016, 5% lower than the previous quarter. Lower second quarter production was due to limited capital activity levels and the divestment of certain non-core assets located in northwest Alberta in June 2016. In the second quarter, Enerplus spent approximately $7.1 million on waterflood optimization activities. Enerplus will continue to focus on cost management in these assets which is helping to deliver strong operating netbacks.

Production and Capital Spending

	Three months ended June 30, 2016		Six months ended June 30, 2016
	Average Production Volumes	Capital Spending ($ millions)	Average Production Volumes	Capital Spending ($ millions)

Crude Oil & NGLs (bbls/day)
Canada	14,915	7.1	15,453	26.2
United States	28,993	31.6	29,002	52.3

Total Crude Oil & NGLs (bbls/day)	43,908	38.7	44,455	78.5

Natural Gas (Mcf/day)
Canada	79,878	0.1	89,708	0.1
United States	218,625	9.3	218,119	12.8

Total Natural Gas (Mcf/day)	298,503	9.4	307,827	12.9

Company Total (BOE/day)	93,659	48.1	95,759	91.4

Net Drilling Activity⁽¹⁾ – for the three months ended June 30, 2016

	Wells Drilled	Wells On-stream

Crude Oil
Canada	–	–
United States	4.6	7.2

Total Crude Oil	4.6	7.2

Natural Gas
Canada	–	–
United States	0.3	1.8

Total Natural Gas	0.3	1.8

Company Total	4.9	9.1

(1): Table may not add due to rounding

4 ENERPLUS 2016 Q2 REPORT

Crude Oil & Natural Gas Pricing

Enerplus' average crude oil selling price during the second quarter was $46.48 per barrel, an increase of 47% compared to the prior quarter as a result of the higher benchmark crude oil prices and narrowing Canadian differentials. Benchmark West Texas Intermediate (WTI) crude oil prices increased by 36% quarter-over-quarter to average US$45.59 per barrel in the second quarter. Enerplus' realized pricing outperformed benchmark WTI prices as light and heavy crude differentials in Canada improved by 16% and 7% respectively, compared to the previous quarter, due to industry wide production outages resulting from the severe wildfires in northern Alberta. These outages also supported U.S. Bakken crude differentials which improved by 2% quarter-over-quarter.

Enerplus' average natural gas selling price during the second quarter was $1.49 per Mcf, 16% lower than the prior quarter, reflecting the significant weakness experienced in Western Canadian gas prices during the period. Benchmark NYMEX gas prices fell by 7% in the second quarter, while in Canada benchmark AECO monthly natural gas prices were 41% weaker than in the first quarter of 2016 in large part due to excessive inventory levels caused by mild winter weather. Supported by Enerplus' AECO basis hedging contracts, the Company's realized Canadian gas price differential significantly outperformed the AECO benchmark price, averaging US$0.86 per Mcf below NYMEX during the quarter compared to the benchmark AECO monthly differential of US$0.99 per Mcf below NYMEX.

Enerplus' realized Marcellus differential improved by 16% during the second quarter to average US$0.76 per Mcf below NYMEX. Industry rig counts in the Marcellus region have fallen meaningfully over the past year which has moderated Northeast Pennsylvania production growth and improved price differentials to NYMEX. Enerplus expects its Marcellus differential to widen in the third quarter with stronger NYMEX prices.

Risk Management

Enerplus continues to protect a portion of funds flow through commodity hedging. Based on 2016 forecast net oil production after royalties, Enerplus has approximately 39% of volumes protected in the second half of 2016 and 2017 through collar structures. Based on 2016 forecast net natural gas production after royalties, Enerplus has approximately 29% and 20% of volumes protected in the second half of 2016 and 2017 respectively, through a combination of swaps and collar structures.

Commodity Hedging Detail (as at July 22, 2016)

	WTI Crude Oil (US$/bbl)(1)				NYMEX Natural Gas (US$/Mcf)(1)
		Jul 1, 2016 – Dec 31, 2016		Jan 1, 2017 – Dec 31, 2017		Jul 1, 2016 – Oct 31, 2016		Nov 1, 2016 – Dec 31, 2016		Jan 1, 2017 – Dec 31, 2017

Swaps
Sold Swaps		–		–	$	2.53	$	2.48		–
Volume (bbl/d or Mcf/d)		–		–		50,000		25,000		–
% of net production		–		–		22%		11%		–
3 Way Collars
Sold Puts	$	45.09	$	38.59	$	2.50	$	2.50	$	2.03
Volume (bbl/d or Mcf/d)		12,000		12,000		25,000		25,000		45,000
% of net production		39%		39%		11%		11%		20%
Purchased Puts	$	57.82	$	50.00	$	3.00	$	3.00	$	2.72
Volume (bbl/d or Mcf/d)		12,000		12,000		25,000		25,000		45,000
% of net production		39%		39%		11%		11%		20%
Sold Calls	$	71.75	$	60.50	$	3.75	$	3.75	$	3.37
Volume (bbl/d or Mcf/d)		12,000		12,000		25,000		25,000		45,000
% of net production		39%		39%		11%		11%		20%

(1): Based on weighted average price (before premiums), assuming average annual production of 93,000 BOE/day for 2016 and 2017, less royalties and production taxes of 22% in aggregate

ENERPLUS 2016 Q2 REPORT 5

2016 Revised Guidance

Enerplus has revised its full year 2016 guidance to reflect stronger natural gas production from the Marcellus, a lower expected overall royalty expense, reduced operating and G&A expenses, and a modest increase in capital spending to support 2017 growth.

Summary of 2016 Expectations	Revised Guidance	Previous Guidance

Capital spending	$215 million	$200 million
Average annual production	92,000 – 94,000 BOE/day	90,000 – 94,000 BOE/day
Crude oil and natural gas liquids volumes	43,000 – 45,000 barrels/day	43,000 – 45,000 barrels/day
Average royalty and production tax rate	22%	23%
Operating expenses	$7.90/BOE	$8.50/BOE
Transportation expense	$3.10/BOE	$3.10/BOE
Cash G&A expenses	$1.95/BOE	$2.00/BOE

Currency and Accounting Principles

All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".

Barrels of Oil Equivalent

This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.

Presentation of Production Information

Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest.

Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.

Forward-Looking Information and Statements

This news release 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", "should", "believe", "plans", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected 2016 average production volumes and the anticipated production mix; the proportion of anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting funds flow; the results from drilling programs and the timing of related production; oil and natural gas prices and differentials and commodity and foreign exchange risk management programs in 2016 and in 2017; expectations regarding realized oil and natural gas prices; anticipated cash and non-cash G&A, share based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016, anticipated drilling and completions program, and the expected impact on production levels; potential future asset impairments; future debt and working capital levels and debt to funds flow ratios.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; current commodity price and cost assumptions; the general continuance of current or,

6 ENERPLUS 2016 Q2 REPORT

where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments as needed; availability of third party services; and the extent of its liabilities. In addition, Enerplus' 2016 revised guidance is based on the following assumptions: WTI crude oil price of US$42.61/bbl, NYMEX gas price of US$2.46/Mcf, and AECO gas price of $2.00/GJ, and USD/CDN exchange rate of 1.32. 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.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes, including future decline, in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from Enerplus' capital spending activities or production declines; curtailment of Enerplus' 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 development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; Enerplus' inability to comply with covenants under its bank credit facility and senior notes; changes in estimates of Enerplus' oil and gas reserves and resources 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; failure to complete any anticipated acquisitions or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in its AIF and Form 40-F at December 31, 2015).

Non-GAAP Measures

In this news release, we use the terms "funds flow" and "debt to funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Debt to funds flow ratio" is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. In addition, "senior debt to adjusted EBITDA" is used to determine Enerplus' compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of these terms is described in Enerplus Corporation's Second Quarter 2016 MD&A under the "Liquidity and Capital Resources" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow" and "debt to funds flow" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures, and "senior debt to adjusted EBITDA" measures, are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Second Quarter 2016 MD&A.

Electronic copies of Enerplus Corporation's Second Quarter 2016 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of our audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

ENERPLUS 2016 Q2 REPORT 7

MD&A

MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

The following discussion and analysis of financial results is dated August 4, 2016 and is to be read in conjunction with:

•: the unaudited interim consolidated financial statements of Enerplus Corporation ("Enerplus" or the "Company") as at and for the three and six months ended June 30, 2016 and 2015 (the "Interim Financial Statements");
•: the audited consolidated financial statements of Enerplus as at December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013; and
•: our MD&A for the year ended December 31, 2015 (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.

BASIS OF PRESENTATION

The Interim Financial Statements and notes 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.

Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and natural gas liquids ("NGL") have been converted to thousand cubic feet of gas equivalent ("Mcfe") based on 0.167 bbl:1 Mcfe. 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, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are 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 unless otherwise stated. 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.

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 peers.

OVERVIEW

During the second quarter, we continued to position ourselves to deliver profitable growth in a low commodity price environment. The proceeds from our equity issuance and the ongoing success of our non-core asset divestment program allowed us to significantly reduce our debt and strengthen our balance sheet. Operationally, our assets continue to deliver strong results with improving cost structures.

On May 31, 2016, we completed an equity financing for 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million net of issue costs). Our non-core asset divestment program continued to provide significant liquidity, with proceeds of $92.7 million during the second quarter and total proceeds of approximately $280.5 million to date in 2016. These proceeds were used to fully repay our drawn credit facility and fund the repurchase of an additional US$95 million of our senior notes during the quarter, for a total repurchase of US$267 million of senior notes to date, at prices ranging from 90% of par to par value. Through these steps we have reduced our total debt net of cash by 45% to $674.1 million at June 30, 2016 from $1,216.2 million at December 31, 2015.

Average daily production for the second quarter was 93,659 BOE/day, at the high end of our annual average production guidance range, and as a result we are increasing the low end of our annual guidance range to 92,000 BOE/day, with the upper end remaining at 94,000 BOE/day. We continue to expect to produce approximately 43,000 – 45,000 bbls/day of crude oil and natural gas liquids. Production decreased approximately 4% from the first quarter of 2016 largely due to the first quarter sale of our Canadian Deep Basin natural gas properties, along with overall

8 ENERPLUS 2016 Q2 REPORT

decline in Canadian production volumes as a result of lower capital spending. Production volumes in the U.S. remained flat compared to the prior quarter, with the impact of lower capital spending offset by strong performance in the Marcellus and Fort Berthold areas.

We maintained a disciplined capital program, spending $48.1 million during the second quarter and $91.4 million year to date, with the majority directed to our Fort Berthold properties. We are modestly increasing our spending in Fort Berthold during the second half of the year to position ourselves for growth in 2017. We plan to spend an additional $15 million on three gross completions and pre-spending on facilities, and are projecting our fourth quarter production to increase by approximately 1,000 BOE/day. As a result, we are increasing our 2016 capital guidance to $215 million from $200 million, which is expected to be funded through internally generated cash flow at current forward strip commodity prices.

Operating expenses came in below guidance of $8.50/BOE, totaling $60.5 million or $7.10/BOE during the second quarter. The decrease in operating costs was mainly due to the ongoing success of our cost savings initiatives, reduced activity levels and continued improvement in pricing for materials and services, along with the divestment of higher cost Canadian properties. As a result, we are reducing our annual guidance for operating expenses to $7.90/BOE from $8.50/BOE. Cash G&A expenses were also below guidance, totaling $14.6 million or $1.71/BOE compared to guidance of $2.00/BOE, primarily due to a reduction in staff levels. Accordingly, we are revising our annual cash G&A expense guidance to $1.95/BOE from $2.00/BOE.

Our commodity hedging program continued to provide funds flow protection, contributing cash gains of $21.6 million in the second quarter. We added additional downside protection during the second quarter, and as of July 22, 2016, we have approximately 39% of our forecasted 2016 crude oil production, net of royalties, hedged for the remainder of 2016 and 2017. We have also hedged approximately 29% of our forecasted 2016 natural gas production, net of royalties, for the remainder of 2016 and approximately 20% for 2017.

We recorded a net loss of $168.6 million and funds flow of $76.0 million for the quarter. Second quarter earnings included gains of $74.7 million on asset divestments and $12.2 million on the repurchase of senior notes. These gains were offset by a non-cash impairment charge of $148.7 million and a non-cash valuation allowance on our deferred tax asset of $105.0 million as a result of the decline in the twelve month trailing average commodity prices.

RESULTS OF OPERATIONS

Production

Production for the second quarter totaled 93,659 BOE/day, at the high end of our annual average guidance range of 90,000 – 94,000 BOE/day. Compared to production in the first quarter of 2016 of 97,860 BOE/day, production decreased 4% primarily due to the first quarter sale of Canadian Deep Basin natural gas properties with production of approximately 5,400 BOE/day.

Production in the second quarter of 2016 decreased 13% from production levels of 107,429 BOE/day in the same period of 2015 primarily due to the sale of non-core properties with production of approximately 9,000 BOE/day during the second half of 2015 and the first quarter of 2016. This excludes the June sale of approximately 2,300 BOE/day of non-core Canadian assets. Production volumes from our Canadian assets were further impacted by the reduction in capital spending in 2015 and 2016, while strong performance from our U.S. assets offset any decline due to lower spending.

As a result of the sale of the Deep Basin natural gas properties and other non-core Canadian shallow gas properties, our crude oil and natural gas liquids weighting increased to 47% of our total average daily production in the second quarter of 2016, from 46% in the first quarter of 2016 and 43% in the second quarter of 2015.

Average daily production volumes for the three and six months ended June 30, 2016 and 2015 are outlined below:

	Three months ended June 30,			Six months ended June 30,
Average Daily Production Volumes	2016	2015	% Change	2016	2015	% Change

Crude oil (bbls/day)	39,079	41,122	(5%)	39,294	40,243	(2%)
Natural gas liquids (bbls/day)	4,829	5,145	(6%)	5,161	4,444	16%
Natural gas (Mcf/day)	298,503	366,971	(19%)	307,827	356,836	(14%)

Total daily sales (BOE/day)	93,659	107,429	(13%)	95,759	104,160	(8%)

ENERPLUS 2016 Q2 REPORT 9

As a result of strong performance and higher natural gas prices expected in the Marcellus, and despite the sale of approximately 2,300 BOE/day of non-core assets in June, we are increasing the lower end of our average annual production guidance to 92,000 – 94,000 BOE/day from 90,000 – 94,000 BOE/day. We are maintaining our annual crude oil and natural gas liquids production guidance of 43,000 – 45,000 bbls/day. This guidance does not include any additional acquisitions or divestments.

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, funds flow and financial condition. The following table compares average prices from the first half of 2016 to the first half of 2015 and other periods indicated:

		Six months ended June 30,
Pricing (average for the period)			2016			2015			Q2 2016			Q1 2016			Q4 2015			Q3 2015			Q2 2015

Benchmarks
	WTI crude oil (US$/bbl)	$	39.52		$	53.29		$	45.59		$	33.45		$	42.18		$	46.43		$	57.94
	AECO natural gas – monthly index ($/Mcf)		1.68			2.81			1.25			2.11			2.65			2.80			2.67
	AECO natural gas – daily index ($/Mcf)		1.62			2.70			1.40			1.83			2.47			2.90			2.64
	NYMEX natural gas – last day (US$/Mcf)		2.02			2.81			1.95			2.09			2.27			2.77			2.64
	USD/CDN average exchange rate		1.33			1.24			1.29			1.37			1.34			1.31			1.23
	USD/CDN period end exchange rate		1.30			1.25			1.30			1.30			1.38			1.34			1.25
Enerplus selling price(1)
	Crude oil ($/bbl)	$	39.00		$	51.35		$	46.48		$	31.59		$	43.04		$	48.22		$	58.26
	Natural gas liquids ($/bbl)		13.37			21.55			15.67			11.34			16.61			13.51			20.88
	Natural gas ($/Mcf)		1.64			2.32			1.49			1.77			1.89			2.08			2.09

Average differentials
	MSW Edmonton – WTI (US$/bbl)	$	(3.39	)	$	(4.93	)	$	(3.09	)	$	(3.69	)	$	(2.44	)	$	(3.42	)	$	(3.06	)
	WCS Hardisty – WTI (US$/bbl)		(13.77	)		(13.16	)		(13.30	)		(14.24	)		(14.50	)		(13.27	)		(11.59	)
	Transco Leidy monthly – NYMEX (US$/Mcf)		(0.84	)		(1.63	)		(0.70	)		(0.99	)		(1.15	)		(1.66	)		(1.50	)
	TGP Z4 300L monthly – NYMEX (US$/Mcf)		(0.90	)		(1.67	)		(0.73	)		(1.07	)		(1.23	)		(1.75	)		(1.57	)
	AECO monthly – NYMEX (US$/Mcf)		(0.76	)		(0.54	)		(0.99	)		(0.56	)		(0.28	)		(0.63	)		(0.47	)
Enerplus realized differentials(1)
	Canada crude oil – WTI (US$/bbl)	$	(13.46	)	$	(14.13	)	$	(12.01	)	$	(14.14	)	$	(13.63	)	$	(11.82	)	$	(12.50	)
	Canada natural gas – NYMEX (US$/Mcf)		(0.74	)		(0.46	)		(0.86	)		(0.63	)		(0.42	)		(0.43	)		(0.46	)
	Bakken crude oil – WTI (US$/bbl)		(8.29	)		(10.05	)		(8.23	)		(8.38	)		(7.93	)		(8.52	)		(9.30	)
	Marcellus natural gas – NYMEX (US$/Mcf)		(0.83	)		(1.35	)		(0.76	)		(0.91	)		(1.13	)		(1.64	)		(1.39	)

(1): Before transportation costs, royalties and commodity derivative instruments.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our average realized crude oil price during the second quarter was $46.48/bbl, an increase of 47% compared to the prior quarter as a result of the higher benchmark crude oil prices and narrowing Canadian differentials. WTI crude oil prices increased by 36% to average US$45.59/bbl in the quarter due to improving seasonal demand for crude oil in the U.S. combined with lower overall U.S. production. Canadian light and heavy crude oil differentials improved by 16% and 7%, respectively, when compared to the previous quarter, due to industry wide production outages resulting from the severe wildfires in northern Alberta. These outages also helped U.S. Bakken crude oil differentials to improve by 2%. In the second quarter our realized natural gas liquids price increased by 38% compared to the first quarter, in-line with the increases in benchmark crude oil and liquids prices during the quarter.

NATURAL GAS

Our average realized natural gas price during the second quarter was $1.49/Mcf, 16% lower when compared to the prior quarter. Benchmark NYMEX and AECO monthly natural gas prices in the second quarter fell by 7% and 41%, respectively, compared to the previous quarter due to high inventory levels as a result of one of the warmest winters on record. Approximately 33% of our second quarter Canadian gas production was sold under fixed basis contracts. As a result, our realized Canadian natural gas price differential significantly outperformed the AECO benchmark price, averaging US$0.86/Mcf below NYMEX during the quarter compared to the benchmark AECO monthly differential of US$0.99/Mcf below NYMEX.

10 ENERPLUS 2016 Q2 REPORT

Industry rig counts in the Marcellus region have fallen dramatically over the past year, resulting in lower production growth in Northeast Pennsylvania and improved price differentials to NYMEX. Monthly differentials at Transco Leidy and TGP Zone 4 300 Leg improved by 29% and 32%, respectively, compared to the prior quarter and 53% compared to the second quarter of 2015. In comparison, our realized Marcellus differential improved by 16% during the second quarter, and 45% compared to the same period last year, to average US$0.76/Mcf below NYMEX. With a portion of our second quarter natural gas sales exposed to other regional prices that were seasonally weaker, our Marcellus realized differential did not improve as much as the local Leidy and TGP benchmarks.

FOREIGN EXCHANGE

The Canadian dollar strengthened throughout the second quarter as a result of higher crude oil prices. The USD/CDN exchange rate was 1.30 USD/CDN at June 30, 2016, and averaged 1.29 USD/CDN during the second quarter compared to 1.37 USD/CDN during the first quarter. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a stronger Canadian dollar relative to the U.S. dollar decreases the amount of our realized sales. Because we report in Canadian dollars, the fluctuations in the Canadian dollar also impact our U.S. dollar denominated costs, capital spending and the reported value of our U.S. dollar denominated debt.

Price Risk Management

We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions. Since our first quarter, we have added additional floor protection on a portion of our oil and natural gas production for 2016 and 2017.

As of July 22, 2016, we have hedged 12,000 bbls/day of our expected crude oil production for the remainder of 2016 and 2017, which represents approximately 39% of our forecasted 2016 net crude oil production, after royalties. Price protection levels are shown in the table below. For the second half of 2016 and the full year of 2017, we have floor protection at an effective price of US$57.82/bbl and US$50.00/bbl, respectively. When WTI prices settle below the sold put strike price in any given month, the three way collars provide protection of approximately US$12.73/bbl and US$11.41/bbl above the WTI index prices in 2016 and 2017, respectively. Overall, we expect our crude oil related hedge contracts to protect a significant portion of our funds flow.

As of July 22, 2016, we have hedged approximately 66,700 Mcf/day of our expected natural gas production for the remainder of 2016 consisting of a combination of NYMEX swaps and collars. This represents approximately 29% of our forecasted natural gas production, after royalties. For 2017 we have hedged 45,000 Mcf/day or approximately 20% of our forecasted 2016 natural gas production, after royalties, using three way collars. Price protection levels are shown in the table below. With regards to the NYMEX three way collars, when NYMEX prices settle below the sold put strike price in any given month, the three way collars provide protection of approximately US$0.50/Mcf and US$0.69/Mcf above the NYMEX index price in 2016 and 2017, respectively.

The following is a summary of our financial contracts in place at July 22, 2016, expressed as a percentage of our anticipated net 2016 production volumes:

	WTI Crude Oil (US$/bbl)(1)				NYMEX Natural Gas (US$/Mcf)(1)
		Jul 1, 2016 – Dec 31, 2016		Jan 1, 2017 – Dec 31, 2017		Jul 1, 2016 – Oct 31, 2016		Nov 1, 2016 – Dec 31, 2016		Jan 1, 2017 – Dec 31, 2017

Sold Swaps		–		–	$	2.53	$	2.48		–
%		–		–		22%		11%		–
Three Way Collars
Sold Puts	$	45.09	$	38.59	$	2.50	$	2.50	$	2.03
%		39%		39%		11%		11%		20%
Purchased Puts	$	57.82	$	50.00	$	3.00	$	3.00	$	2.72
%		39%		39%		11%		11%		20%
Sold Calls	$	71.75	$	60.50	$	3.75	$	3.75	$	3.37
%		39%		39%		11%		11%		20%

(1): Based on weighted average price (before premiums), assuming average annual production of 93,000 BOE/day for 2016 and 2017 less royalties and production taxes of 22% in aggregate.

ENERPLUS 2016 Q2 REPORT 11

ACCOUNTING FOR PRICE RISK MANAGEMENT

Commodity Risk Management Gains/(Losses)		Three months ended June 30,						Six months ended June 30,
($ millions)			2016			2015			2016			2015

Cash gains/(losses):
	Crude oil	$	16.4		$	56.7		$	52.9		$	127.2
	Natural gas		5.2			16.4			8.3			32.7

Total cash gains/(losses)		$	21.6		$	73.1		$	61.2		$	159.9
Non-cash gains/(losses):
	Crude oil	$	(27.2	)	$	(71.1	)	$	(58.4	)	$	(107.1	)
	Natural gas		(16.3	)		(21.8	)		(11.2	)		(22.2	)

Total non-cash gains/(losses)		$	(43.5	)	$	(92.9	)	$	(69.6	)	$	(129.3	)

Total gains/(losses)		$	(21.9	)	$	(19.8	)	$	(8.4	)	$	30.6

	Three months ended June 30,						Six months ended June 30,
(Per BOE)		2016			2015			2016			2015

Total cash gains/(losses)	$	2.53		$	7.47		$	3.51		$	8.48
Total non-cash gains/(losses)		(5.10	)		(9.49	)		(3.99	)		(6.85	)

Total gains/(losses)	$	(2.57	)	$	(2.02	)	$	(0.48	)	$	1.63

During the second quarter of 2016 we realized cash gains of $16.4 million on our crude oil contracts and $5.2 million on our natural gas contracts. In comparison, during the second quarter of 2015 we realized cash gains of $56.7 million on our crude oil contracts and $16.4 million on our natural gas contracts. The cash gains were due to contracts which provided floor protection above market prices.

As the forward markets for crude oil and natural gas fluctuate and new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At the end of the second quarter of 2016 the fair value of our crude oil contracts represented a net gain position of $9.0 million, while our natural gas contracts represented a net loss position of $7.2 million. For the three and six months ended June 30, 2016, the change in the fair value of our crude oil contracts represented losses of $27.2 million and $58.4 million, respectively, and our natural gas contracts represented losses of $16.3 million and $11.2 million, respectively.

Revenues

	Three months ended June 30,						Six months ended June 30,
($ millions)		2016			2015			2016			2015

Oil and natural gas sales	$	212.7		$	298.4		$	383.2		$	542.5
Royalties		(38.4	)		(46.7	)		(66.2	)		(85.8	)

Oil and natural gas sales, net of royalties	$	174.3		$	251.7		$	317.0		$	456.7

Oil and natural gas revenues for the three and six months ended June 30, 2016 were $212.7 million and $383.2 million, respectively, a decrease of 31% from the same periods in 2015. The decrease in revenue was a result of the decline in oil and natural gas prices over the respective periods, as well as the impact of lower production volumes.

12 ENERPLUS 2016 Q2 REPORT

Royalties and Production Taxes

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2016		2015		2016		2015

Royalties	$	38.4	$	46.7	$	66.2	$	85.8
Per BOE	$	4.51	$	4.78	$	3.80	$	4.55
Production taxes	$	8.6	$	14.2	$	16.0	$	25.0
Per BOE	$	1.00	$	1.45	$	0.92	$	1.33

Royalties and production taxes	$	47.0	$	60.9	$	82.2	$	110.8
Per BOE	$	5.51	$	6.23	$	4.72	$	5.88
Royalties and production taxes (% of oil and natural gas sales)		22%		20%		21%		20%

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees, freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally not as sensitive to commodity price levels. During the three and six months ended June 30, 2016, royalties and production taxes decreased to $47.0 million and $82.2 million, respectively, from $60.9 million and $110.8 million for the same periods in 2015, primarily due to lower realized prices and lower production volumes. Royalties and production taxes averaged 21% of oil and natural gas sales before transportation costs in the first half of 2016 compared to 20% for the same period in 2015 due to increased production from our U.S. properties.

We have revised our average royalty and production tax rate guidance to 22% of oil and gas sales for 2016 from 23%. We do not expect the recently announced Alberta modernized royalty framework to have a significant impact on our Canadian royalties.

Operating Expenses

	Three months ended June 30,						Six months ended June 30,
($ millions, except per BOE amounts)		2016			2015			2016			2015

Cash operating expenses	$	61.4		$	79.3		$	133.7		$	166.2
Non-cash (gains)/losses(1)		(0.9	)		(2.6	)		(0.6	)		(1.7	)

Total operating expenses	$	60.5		$	76.7		$	133.1		$	164.5
Per BOE	$	7.10		$	7.85		$	7.64		$	8.72

(1): Non-cash (gains)/losses on fixed price electricity swaps.

For the three and six months ended June 30, 2016, operating expenses were $60.5 million and $133.1 million, respectively, a decrease of 21% and 19% compared to the same periods in 2015. On a per BOE basis, operating costs for the three and six months ended June 30, 2016 were $7.10/BOE and $7.64/BOE, outperforming our annual guidance of $8.50/BOE. The decrease in operating costs was mainly a result of our continued cost saving initiatives and the divestment of higher operating cost Canadian properties over the last year.

Based on cost savings to date, we are reducing our 2016 guidance for operating expenses to $7.90/BOE from $8.50/BOE.

Transportation Costs

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2016		2015		2016		2015

Transportation costs	$	24.5	$	28.0	$	50.2	$	54.5
Per BOE	$	2.87	$	2.87	$	2.88	$	2.89

For the three and six months ended June 30, 2016, transportation costs were $24.5 million ($2.87/BOE) and $50.2 million ($2.88/BOE), respectively, compared to $28.0 million ($2.87/BOE) and $54.5 million ($2.89/BOE) for the same periods in 2015. The decrease in transportation costs was primarily due to lower production.

We are maintaining our 2016 guidance for transportation costs of $3.10/BOE. Although year to date transportation costs are below our annual guidance, effective August 2016 we have firm transportation commitments for 30,000 Mcf/day of additional interstate pipeline capacity from the Marcellus region to downstream connections at pricing of US$0.71/Mcf.

ENERPLUS 2016 Q2 REPORT 13

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, 2016
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			46,972 BOE/day			280,122 Mcfe/day			93,659 BOE/day

	Netback(1) $ per BOE or Mcfe		(per BOE	)		(per Mcfe	)		(Per BOE	)

	Oil and natural gas sales	$	40.57		$	1.54		$	24.96
	Royalties and production taxes		(9.57	)		(0.24	)		(5.51	)
	Cash operating expenses		(10.04	)		(0.73	)		(7.20	)
	Transportation costs		(1.85	)		(0.64	)		(2.87	)

	Netback before hedging	$	19.11		$	(0.07	)	$	9.38

	Cash gains/(losses)		3.83			0.20			2.53

	Netback after hedging	$	22.94		$	0.13		$	11.91

	Netback before hedging ($ millions)	$	81.6		$	(1.8	)	$	79.8

	Netback after hedging ($ millions)	$	98.0		$	3.4		$	101.4

		Three months ended June 30, 2015
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			49,058 BOE/day			350,226 Mcfe/day			107,429 BOE/day

	Netback(1) $ per BOE or Mcfe		(per BOE	)		(per Mcfe	)		(Per BOE	)

	Oil and natural gas sales	$	52.17		$	2.06		$	30.53
	Royalties and production taxes		(12.15	)		(0.21	)		(6.23	)
	Cash operating expenses		(11.27	)		(0.91	)		(8.12	)
	Transportation costs		(1.68	)		(0.64	)		(2.87	)

	Netback before hedging	$	27.07		$	0.30		$	13.31

	Cash gains/(losses)		12.69			0.52			7.47

	Netback after hedging	$	39.76		$	0.82		$	20.78

	Netback before hedging ($ millions)	$	121.0		$	9.2		$	130.2

	Netback after hedging ($ millions)	$	177.6		$	25.7		$	203.3

		Six months ended June 30, 2016
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			47,836 BOE/day			287,538 Mcfe/day			95,759 BOE/day

	Netback(1) $ per BOE or Mcfe		(per BOE	)		(per Mcfe	)		(Per BOE	)

	Oil and natural gas sales	$	33.82		$	1.70		$	21.99
	Royalties and production taxes		(7.95	)		(0.25	)		(4.72	)
	Cash operating expenses		(10.06	)		(0.88	)		(7.67	)
	Transportation costs		(1.85	)		(0.65	)		(2.88	)

	Netback before hedging	$	13.96		$	(0.08	)	$	6.72

	Cash gains/(losses)		6.08			0.16			3.51

	Netback after hedging	$	20.04		$	0.08		$	10.23

	Netback before hedging ($ millions)	$	121.5		$	(4.4	)	$	117.1

	Netback after hedging ($ millions)	$	174.5		$	3.8		$	178.3

14 ENERPLUS 2016 Q2 REPORT

		Six months ended June 30, 2015
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			46,916 BOE/day			343,464 Mcfe/day			104,160 BOE/day

	Netback(1) $ per BOE or Mcfe		(per BOE	)		(per Mcfe	)		(Per BOE	)

	Oil and natural gas sales	$	46.98		$	2.31		$	28.78
	Royalties and production taxes		(10.99	)		(0.28	)		(5.88	)
	Cash operating expenses		(12.31	)		(0.99	)		(8.81	)
	Transportation costs		(1.82	)		(0.63	)		(2.89	)

	Netback before hedging	$	21.86		$	0.41		$	11.20

	Cash gains/(losses)		14.98			0.53			8.48

	Netback after hedging	$	36.84		$	0.94		$	19.68

	Netback before hedging ($ millions)	$	185.6		$	25.4		$	211.0

	Netback after hedging ($ millions)	$	312.9		$	58.0		$	370.9

(1): See "Non-GAAP Measures" in this MD&A.

Crude oil and natural gas netbacks per BOE decreased for the three and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to lower commodity prices and lower realized hedging gains. Our crude oil properties accounted for substantially all of our netback, both before and after hedging.

General and Administrative Expenses

Total G&A expenses include cash G&A expenses and share-based compensation ("SBC") charges related to our long-term incentive plans ("LTI plans") and our stock option plan. See Note 10 and Note 14 to the Interim Financial Statements for further details.

		Three months ended June 30,						Six months ended June 30,
($ millions)			2016			2015			2016			2015

Cash:
	G&A expense	$	14.6		$	19.9		$	33.0		$	41.3
	Share-based compensation expense		0.8			(1.2	)		1.5			6.0
Non-Cash:
	Share-based compensation expense		5.4			4.6			8.9			9.6
	Equity swap loss/(gain)		(1.6	)		1.0			(1.7	)		(0.6	)

Total G&A expenses		$	19.2		$	24.3		$	41.7		$	56.3

		Three months ended June 30,						Six months ended June 30,
(Per BOE)			2016			2015			2016			2015

Cash:
	G&A expense	$	1.71		$	2.03		$	1.89		$	2.19
	Share-based compensation expense		0.09			(0.13	)		0.09			0.32
Non-Cash:
	Share-based compensation expense		0.63			0.47			0.51			0.51
	Equity swap loss/(gain)		(0.18	)		0.11			(0.10	)		(0.03	)

Total G&A expenses		$	2.25		$	2.48		$	2.39		$	2.99

For the three and six months ended June 30, 2016, cash G&A expenses were $14.6 million ($1.71/BOE) and $33.0 million ($1.89/BOE), respectively, compared to $19.9 million ($2.03/BOE) and $41.3 million ($2.19/BOE) for the same periods in 2015. The decrease in cash G&A expenses from the prior year was primarily due to a 30% reduction in staff levels throughout 2015 and to date in 2016, offset by one-time severance payments, as we continue to respond to the current commodity price environment.

ENERPLUS 2016 Q2 REPORT 15

During the quarter, our share price increased by 67% resulting in a cash SBC expense of $0.8 million ($0.09/BOE) compared to a recovery of $1.2 million ($0.13/BOE) in the same period of 2015. We recorded non-cash SBC of $5.4 million ($0.63/BOE) in the second quarter compared to $4.6 million ($0.47/BOE) during the same period in 2015. The increase in non-cash SBC was due to the additional expense related to the 2016 grant.

We have hedged a portion of the outstanding cash settled grants under our LTI plans. As a result of the increase in our share price during the quarter we recorded a non-cash mark-to-market gain of $1.6 million on these hedges. As of June 30, 2016 we had 470,000 units hedged at a weighted average price of $16.89 per share.

Based on our continued focus on costs, we are reducing our 2016 guidance for cash G&A expenses to $1.95/BOE from $2.00/BOE.

Interest Expense

	Three months ended June 30,				Six months ended June 30,
($ millions)		2016		2015		2016		2015

Interest on senior notes and bank facility	$	10.0	$	15.9	$	24.6	$	32.7
Non-cash interest expense		0.6		0.2		0.8		0.5

Total interest expense	$	10.6	$	16.1	$	25.4	$	33.2

For the three and six months ended June 30, 2016, we recorded total interest expense of $10.6 million and $25.4 million, respectively, compared to $16.1 million and $33.2 million for the same periods in 2015. The decrease in interest expense corresponds to a decrease in the aggregate principal amount of our outstanding senior notes following our repurchase of US$267 million of senior notes during the first half of 2016. The repurchase of senior notes was funded by asset divestment proceeds and lower interest rate bank debt, which was repaid in full following our May 31, 2016 equity financing and the closing of our previously announced Canadian non-core asset divestment.

At June 30, 2016, our bank credit facility was undrawn, and our debt balance consisted solely of fixed interest rate senior notes with a weighted average interest rate of 5.0%.

Foreign Exchange

	Three months ended June 30,					Six months ended June 30,
($ millions)		2016		2015			2016			2015

Realized loss/(gain)	$	0.3	$	8.4		$	2.0		$	(27.2	)
Unrealized loss/(gain)		0.1		(36.1	)		(56.0	)		103.7

Total foreign exchange loss/(gain)	$	0.4	$	(27.7	)	$	(54.0	)	$	76.5

USD/CDN average exchange rate		1.29		1.23			1.33			1.24

For the three and six months ended June 30, 2016, we recorded a net foreign exchange loss of $0.4 million and a net foreign exchange gain of $54.0 million, respectively, compared to a gain of $27.7 million and a loss of $76.5 million for the same periods in 2015. Realized losses related to day-to-day transactions recorded in foreign currencies. During the six months ended June 30, 2015 we recorded realized gains of $27.2 million primarily due to a $39.9 million gain on the unwind of certain foreign exchange swaps offset by losses on our foreign exchange collars.

Unrealized foreign exchange gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing June 30, 2016 to December 31, 2015, the Canadian dollar strengthened relative to the U.S. dollar resulting in unrealized gains of $56.0 million. See Note 12 to the Interim Financial Statements for further details.

16 ENERPLUS 2016 Q2 REPORT

Capital Investment

	Three months ended June 30,						Six months ended June 30,
($ millions)		2016			2015			2016			2015

Capital spending	$	48.1		$	148.0		$	91.4		$	315.0
Office capital		0.1			1.4			0.1			2.3

Sub-total		48.2			149.4			91.5			317.3

Property and land acquisitions	$	0.3		$	(1.0	)	$	3.9		$	(1.2	)
Property divestments		(92.7	)		(187.8	)		(280.5	)		(191.5	)

Sub-total		(92.4	)		(188.8	)		(276.6	)		(192.7	)

Total	$	(44.2	)	$	(39.4	)	$	(185.1	)	$	124.6

Capital spending for the three and six months ended June 30, 2016, totaled $48.1 million and $91.4 million, respectively, compared to $148.0 million and $315.0 million for the same periods in 2015. The decrease is in-line with our reduced spending program for 2016, as we continue to invest modestly in our core areas. During the second quarter we spent $30.4 million on our Fort Berthold crude oil properties, $7.1 million on our Canadian crude properties and $9.4 million on our Marcellus assets.

In June 2016, we completed the previously announced sale of non-core properties in northwest Alberta for proceeds of $92.7 million, net of closing costs, with estimated 2016 production of approximately 2,300 BOE/day. In comparison, during the second quarter of 2015, we sold non-core assets with proceeds of $187.8 million, including our Pembina waterflood assets. Year to date, we have recorded total proceeds on asset divestments of $280.5 million, compared to $191.5 million in the same period of 2015.

We are increasing our 2016 capital guidance by $15 million to $215 million to begin to position ourselves for growth in 2017. The incremental capital will be directed to Fort Berthold, and includes the addition of three gross completions as well as pre-spending on our facilities during the second half of the year. We expect the additional spending to increase our fourth quarter production by approximately 1,000 BOE/day and to be funded through internally generated cash flow at current forward strip commodity prices.

Gain on Asset Sales and Note Repurchases

We recorded a gain of $74.7 million on the sale of non-core Canadian properties during the second quarter of 2016, bringing our year to date gain on asset divestments to $219.8 million. Under full cost accounting rules, divestitures of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre's capitalized costs and proved reserves, then a gain or loss must be recognized. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.

During the second quarter of 2016, we recorded a gain of $12.2 million on the repurchase of US$95 million of outstanding senior notes at a discount to par value. Year to date, we have repurchased a total of US$267 million of senior notes at prices between 90% of par and par value, resulting in a total gain of $19.3 million.

Depletion, Depreciation and Accretion ("DD&A")

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2016		2015		2016		2015

DD&A expense	$	82.3	$	137.4	$	173.5	$	269.8
Per BOE	$	9.66	$	14.06	$	9.95	$	14.31

DD&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three and six months ended June 30, 2016, DD&A decreased when compared the same periods of 2015 primarily due to the cumulative effects of asset impairments recorded during 2015 and the first quarter of 2016.

ENERPLUS 2016 Q2 REPORT 17

Impairment

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. Under U.S. GAAP, impairments are not reversed in future periods.

The trailing twelve month average crude oil and natural gas prices continued to decline in the first half of 2016 but less significantly than in 2015. Non-cash impairments of $148.7 million and $194.9 million were recorded for the three and six months ended June 30, 2016, respectively, compared to $497.2 million and $764.9 million in the same periods of 2015.

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 this year, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. Although the trailing twelve month average commodity prices are near current levels, there is the potential for prices to decline further during 2016, impacting the ceiling value and resulting in further non-cash impairments. See Note 5 to the Interim Financial Statements for trailing twelve month prices.

Asset Retirement Obligation

In connection with our operations we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on our net ownership interest and management's estimate of costs to abandon and reclaim and the timing of the costs to be incurred in future periods. We have estimated the net present value of our asset retirement obligation to be $188.2 million at June 30, 2016, compared to $206.4 million at December 31, 2015. For the three and six months ended June 30, 2016, asset retirement obligation settlements were $0.8 million and $3.2 million, respectively, compared to $2.6 million and $6.5 million during the same periods in 2015. As a result of our divestments to date in 2016, we have reduced our asset retirement obligation by $22.6 million.

Income Taxes

	Three months ended June 30,						Six months ended June 30,
($ millions)		2016			2015			2016			2015

Current tax expense/(recovery)	$	(0.2	)	$	(0.1	)	$	(0.4	)	$	–
Deferred tax expenses/(recovery)		53.3			(221.7	)		309.8			(360.1	)

Total tax expense/(recovery)	$	53.1		$	(221.8	)	$	309.4		$	(360.1	)

For the three and six months ended June 30, 2016 we recorded total tax expense of $53.1 million and $309.4 million, respectively, compared to a tax recovery of $221.8 million and $360.1 million for the same periods in 2015. The current quarter expense includes an additional valuation allowance of $105.0 million recorded against our deferred income tax asset, partially offset by a recovery due to the non-cash asset impairment expense recorded in the U.S. and Canada. We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not that all or a portion of our deferred income tax assets will be realized. Our assessment is primarily based on a projection of undiscounted future taxable income using historical trailing twelve month benchmark prices. After recording the valuation allowance, our overall net deferred income tax asset was $186.7 million at June 30, 2016 compared to $516.1 million at December 31, 2015.

18 ENERPLUS 2016 Q2 REPORT

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess our liquidity and leverage including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging 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, 2016, our senior debt to adjusted EBITDA ratio was 1.2x and our debt to funds flow ratio was 2.0x. Although it is not included in our debt covenants, the debt to funds flow ratio is often used by investors and analysts to evaluate our liquidity.

We have continued to be diligent in managing and preserving our financial position. On May 31, 2016 we completed an equity financing for 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million net of issue costs). Our non-core asset divestment program continued to provide significant liquidity, with proceeds of $92.7 million during the second quarter and total proceeds of approximately $280.5 million to date in 2016. These proceeds were used to fully repay our drawn credit facility and fund the repurchase of US$95 million of our senior notes during the quarter, and a total of US$267 million of senior notes to date. The senior note repurchases were completed at prices ranging from 90% of par to par value, resulting in a total gain of $19.3 million for the six months ended June 30, 2016. Furthermore, as a result of the note repurchases we expect to save approximately US$13 million in interest expense on an annualized basis.

Following the equity financing and non-core asset divestments, total debt net of cash at June 30, 2016 was $674.1 million, a decrease of 45% compared to $1,216.2 million at December 31, 2015. At June 30, 2016, we had $723.3 million of senior notes outstanding less $49.2 million in cash and our $800 million bank credit facility was undrawn.

We continued to maintain our financial flexibility through an ongoing focus on cost efficiencies and disciplined capital spending. Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by funds flow, was 72% and 96% for the three and six months ended June 30, 2016, compared to 112% and 147% for the same periods in 2015. After adjusting for net acquisition and divestment proceeds, we had a funding surplus of $282.0 million for the six months ended June 30, 2016.

Our working capital deficiency, excluding cash and current deferred financial assets and liabilities, decreased to $88.5 million at June 30, 2016 from $104.0 million at December 31, 2015. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, funds flow and our bank credit facility. We have sufficient liquidity to meet our financial commitments, as disclosed under "Commitments" in the Annual MD&A.

At June 30, 2016, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Based on our current guidance, we expect to manage our business within these financial ratios; however, current oil and gas prices have created a significant level of uncertainty which may challenge the assumptions and estimates used in management's forecast. If we exceed any of the covenants, we may be required to repay, refinance or renegotiate the terms of the debt. If we reach or exceed these covenant thresholds, there are a number of steps that may be taken to improve them, including asset divestments, a reduction to capital spending and equity issuances.

Our bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.

The following table lists our financial covenants as at June 30, 2016:

Covenant Description		June 30, 2016

Bank Credit Facility:	Maximum Ratio
Senior debt to adjusted EBITDA(1)	3.5 x	1.2 x
Total debt to adjusted EBITDA	4.0 x	1.2 x
Total debt to capitalization	50%	29%
Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA(2)	3.0 x – 3.5 x	1.2 x
Senior debt to consolidated present value of total proved reserves(3)	60%	32%
	Minimum Ratio
Adjusted EBITDA to interest	4.0 x	10.3 x

ENERPLUS 2016 Q2 REPORT 19

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, 2016 were $170.7 million and $603.2 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 may increase to 3.5x for a period of 6 months for the senior notes, 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)		2016		2015		2016		2015

Dividends to shareholders	$	6.5	$	30.9	$	21.0	$	78.3
Per weighted average share (Basic)	$	0.03	$	0.15	$	0.10	$	0.38

During the three and six months ended June 30, 2016, we reported total dividends of $6.5 million or $0.03 per share and $21.0 million or $0.10 per share, respectively, compared to $30.9 million or $0.15 per share and $78.3 million or $0.38 per share for the same periods in 2015.

Effective with the April 2016 payment, we reduced the monthly dividend by 67% from $0.03 per share to $0.01 per share to provide additional financial flexibility and to balance funds flow with capital and dividends. The dividend is an important part of our strategy to create shareholder value and we will continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders' Capital

	Six months ended June 30,
		2016		2015

Share capital ($ millions)	$	3,366.0	$	3,126.6
Common shares outstanding (thousands)		240,483		206,224
Weighted average shares outstanding – basic (thousands)		212,420		206,028
Weighted average shares outstanding – diluted (thousands)		212,420		206,028

On May 31, 2016, 33,350,000 common shares were issued at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million net of issue costs).

During the second quarter no shares were issued pursuant to the stock option plan and the treasury settled LTI plans, resulting in no additional equity for the company (2015 – 45,000; $0.6 million). For the six months ended June 30, 2016 a total of 594,000 shares were issued pursuant to the treasury settled Restricted Share Unit plan resulting in $9.4 million of additional equity (2015 – 492,000; $6.3 million). For further details see Note 14 to the Interim Financial Statements.

At August 4, 2016 we had 240,483,000 shares outstanding.

20 ENERPLUS 2016 Q2 REPORT

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

		Three months ended June 30, 2016									Three months ended June 30, 2015
($ millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes(1)
	Crude oil (bbls/day)		13,497			25,582			39,079			15,462			25,660			41,122
	Natural gas liquids (bbls/day)		1,418			3,411			4,829			2,136			3,009			5,145
	Natural gas (Mcf/day)		79,878			218,625			298,503			144,788			222,183			366,971

	Total average daily production (BOE/day)		28,228			65,431			93,659			41,730			65,699			107,429

Pricing(2)
	Crude oil (per bbl)	$	43.27		$	48.18		$	46.48		$	55.86		$	59.71		$	58.26
	Natural gas liquids (per bbl)		25.14			11.74			15.67			33.58			11.87			20.88
	Natural gas (per Mcf)		1.41			1.52			1.49			2.68			1.70			2.09
Capital Expenditures
	Capital spending	$	7.2		$	40.9		$	48.1		$	24.6		$	123.4		$	148.0
	Acquisitions		1.0			(0.7	)		0.3			0.8			(1.8	)		(1.0	)
	Divestments		(91.1	)		(1.6	)		(92.7	)		(187.1	)		(0.7	)		(187.8	)
Netback(3) Before Hedging
	Oil and natural gas sales	$	66.6		$	146.1		$	212.7		$	120.7		$	177.7		$	298.4
	Royalties		(9.7	)		(28.7	)		(38.4	)		(11.7	)		(35.0	)		(46.7	)
	Production taxes		(0.1	)		(8.5	)		(8.6	)		(0.9	)		(13.3	)		(14.2	)
	Cash operating expenses		(31.4	)		(30.0	)		(61.4	)		(49.3	)		(30.0	)		(79.3	)
	Transportation costs		(3.9	)		(20.6	)		(24.5	)		(5.8	)		(22.2	)		(28.0	)

	Netback before hedging	$	21.5		$	58.3		$	79.8		$	53.0		$	77.2		$	130.2

Other Expenses
	Commodity derivative instruments loss/(gain)	$	21.9		$	–		$	21.9		$	19.8		$	–		$	19.8
	General and administrative expense(4)		14.7			4.5			19.2			19.2			5.1			24.3
	Current income tax expense/(recovery)		(0.4	)		0.2			(0.2	)		(0.4	)		0.3			(0.1	)

ENERPLUS 2016 Q2 REPORT 21

		Six months ended June 30, 2016									Six months ended June 30, 2015
($ millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes(1)
	Crude oil (bbls/day)		13,841			25,453			39,294			16,213			24,030			40,243
	Natural gas liquids (bbls/day)		1,612			3,549			5,161			2,247			2,197			4,444
	Natural gas (Mcf/day)		89,708			218,119			307,827			140,129			216,707			356,836

	Total average daily production (BOE/day)		30,404			65,355			95,759			41,816			62,345			104,160

Pricing(2)
	Crude oil (per bbl)	$	34.70		$	41.33		$	39.00		$	48.37		$	53.56		$	51.35
	Natural gas liquids (per bbl)		25.05			8.07			13.37			31.26			11.62			21.55
	Natural gas (per Mcf)		1.74			1.59			1.64			2.90			1.95			2.32
Capital Expenditures
	Capital spending	$	26.3		$	65.1		$	91.4		$	101.5		$	213.5		$	315.0
	Acquisitions		2.0			1.9			3.9			2.0			(3.2	)		(1.2	)
	Divestments		(279.4	)		(1.1	)		(280.5	)		(188.0	)		(3.5	)		(191.5	)
Netback(3) Before Hedging
	Oil and natural gas sales	$	123.3		$	259.9		$	383.2		$	228.6		$	313.9		$	542.5
	Royalties		(15.1	)		(51.1	)		(66.2	)		(24.0	)		(61.8	)		(85.8	)
	Production taxes		(0.9	)		(15.1	)		(16.0	)		(2.7	)		(22.3	)		(25.0	)
	Cash operating expenses		(74.9	)		(58.8	)		(133.7	)		(106.4	)		(59.8	)		(166.2	)
	Transportation costs		(7.5	)		(42.7	)		(50.2	)		(12.0	)		(42.5	)		(54.5	)

	Netback before hedging	$	24.9		$	92.2		$	117.1		$	83.5		$	127.5		$	211.0

Other Expenses
	Commodity derivative instruments loss/(gain)	$	8.4		$	–		$	8.4		$	(30.6	)	$	–		$	(30.6	)
	General and administrative expense(4)		33.1			8.6			41.7			42.7			13.6			56.3
	Current income tax expense/(recovery)		(0.7	)		0.3			(0.4	)		(0.4	)		0.4			–

(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.

QUARTERLY FINANCIAL INFORMATION

		Oil and Natural Gas Sales, Net of		Net		Net Income/(Loss) Per Share
($ millions, except per share amounts)		Royalties		Income/(Loss)			Basic			Diluted

2016
Second Quarter	$	174.3	$	(168.5	)	$	(0.77	)	$	(0.77	)
First Quarter		142.7		(173.7	)		(0.84	)		(0.84	)

Total 2016	$	317.0	$	(342.2	)	$	(1.61	)	$	(1.61	)

2015
Fourth Quarter	$	199.4	$	(625.0	)	$	(3.03	)	$	(3.03	)
Third Quarter		228.3		(292.7	)		(1.42	)		(1.42	)
Second Quarter		251.7		(312.5	)		(1.52	)		(1.52	)
First Quarter		205.0		(293.2	)		(1.42	)		(1.42	)

Total 2015	$	884.4	$	(1,523.4	)	$	(7.39	)	$	(7.39	)

2014
Fourth Quarter	$	325.3	$	151.7		$	0.74		$	0.73
Third Quarter		378.3		67.4			0.33			0.32
Second Quarter		414.9		40.0			0.20			0.19
First Quarter		407.7		40.0			0.20			0.19

Total 2014	$	1,526.2	$	299.1		$	1.46		$	1.44

22 ENERPLUS 2016 Q2 REPORT

Oil and gas sales, net of royalties, increased in the second quarter compared to the first quarter of 2016 due to higher realized crude oil prices partially offset by lower natural gas prices and lower oil and gas production volumes. Oil and gas sales, net of royalties, increased during the first half of 2014, then decreased throughout 2015 and 2016 as commodity prices declined. During 2015, the impact of weak commodity prices was somewhat offset by increasing production. Net losses reported in 2015 and 2016 were primarily due to non-cash asset impairments and valuation allowances on our deferred tax asset related to the decrease in the trailing twelve month average commodity prices, along with reduced revenues.

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, 2016, we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.

2016 UPDATED GUIDANCE

We have revised our full year 2016 guidance to reflect a modest increase in capital spend to support 2017 growth, stronger natural gas production from the Marcellus, a lower expected overall royalty expense and reduced operating and G&A expenses. All other guidance has been maintained and is summarized below. This guidance includes the second quarter sale of non-core natural gas properties located in northwest Alberta, but does not include any additional acquisitions or divestments.

Summary of 2016 Expectations		Target

Capital spending		$215 million (from $200 million)
Average annual production		92,000 – 94,000 BOE/day (from 90,000 – 94,000 BOE/day)
Crude oil and natural gas liquids volumes		43,000 – 45,000 bbls/day
Average royalty and production tax rate (% of oil and natural gas sales)		22% (from 23%)
Operating expenses		$7.90/BOE (from $8.50/BOE)
Transportation costs		$3.10/BOE
Cash G&A expenses		$1.95/BOE (from $2.00/BOE)

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 our 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)			2016			2015			2016			2015

Oil and natural gas sales		$	212.7		$	298.4		$	383.2		$	542.5
Less:
	Royalties		(38.4	)		(46.7	)		(66.2	)		(85.8	)
	Production taxes		(8.6	)		(14.2	)		(16.0	)		(25.0	)
	Cash operating expenses(1)		(61.4	)		(79.3	)		(133.7	)		(166.2	)
	Transportation costs		(24.5	)		(28.0	)		(50.2	)		(54.5	)

Netback before hedging		$	79.8		$	130.2		$	117.1		$	211.0
	Cash gains/(losses) on derivative instruments		21.6			73.1			61.2			159.9

Netback after hedging		$	101.4		$	203.3		$	178.3		$	370.9

(1): Total operating expenses adjusted to exclude non-cash gains on fixed price electricity swaps of $0.9 million and $0.6 million in the three and six months ended June 30, 2016 and $2.6 million and $1.7 million in the three and six months ended June 30, 2015.

ENERPLUS 2016 Q2 REPORT 23

"Funds Flow" is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. Funds flow is calculated as net cash from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

Reconciliation of Cash Flow from Operating Activities to Funds Flow	Three months ended June 30,				Six months ended June 30,
($ millions)		2016		2015		2016			2015

Cash flow from operating activities	$	61.9	$	135.0	$	131.6		$	266.2
Asset retirement obligation expenditures		0.7		2.6		3.2			6.5
Changes in non-cash operating working capital		13.4		22.8		(17.0	)		(3.1	)

Funds flow	$	76.0	$	160.4	$	117.8		$	269.6

"Debt to Funds Flow Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The debt to funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization 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 our adjusted payout ratio as cash dividends plus capital and office expenditures divided by funds flow.

Calculation of Adjusted Payout Ratio	Three months ended June 30,				Six months ended June 30,
($ millions)		2016		2015		2016		2015

Dividends	$	6.5	$	30.9	$	21.0	$	78.3
Capital and office expenditures		48.2		149.4		91.5		317.3

Sub-total	$	54.7	$	180.3	$	112.5	$	395.6
Funds flow	$	76.0	$	160.4	$	117.8	$	269.6

Adjusted payout ratio (%)		72%		112%		96%		147%

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 proven 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.

Reconciliation of Net Income to Adjusted EBITDA(1) ($ millions)			June 30, 2016

Net income/(loss)		$	(1,259.9	)
Add:
	Interest		59.6
	Current and deferred tax expense/(recovery)		502.0
	DD&A and asset impairment		1,193.4
	Other non-cash charges(2)		129.7

Sub-total		$	624.8
Adjustment for material acquisitions and divestments(3)			(21.6	)

Adjusted EBITDA		$	603.2

(1): Adjusted EBITDA is calculated based on the trailing four quarters. Balances above at June 30, 2016 include the six months ended June 30, 2016 and the third and fourth quarters of 2015.
(2): Includes the change in fair value of commodity derivatives, fixed price electricity swaps and equity swaps, non-cash SBC, and unrealized foreign exchange gains/losses.
(3): EBITDA is adjusted for material acquisitions or divestments during the period with net proceeds greater than $50 million as if that acquisition or disposition had been made at the beginning of the period.

24 ENERPLUS 2016 Q2 REPORT

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, 2016, 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, 2016 and ended June 30, 2016 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, 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.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "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 2016 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management programs in 2016 and 2017; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016 and its impact on our production level and land holdings; potential future asset and goodwill impairments, as well as the relevant factors that may affect such impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and cash taxes; our deferred income taxes; future debt and working capital levels and debt to 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, and to negotiate relief if required; our future acquisitions and divestments, expected timing thereof, production and reductions in asset retirement obligations associated therewith and use of proceeds therefrom; expected gains for accounting purposes in respect to our repurchase of senior notes and our asset divestments; anticipated amount of interest expense savings in respect to our repurchase of senior notes; 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, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices; 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 funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. In addition, our 2016 guidance contained in this MD&A is based on the following: a WTI price of US$42.61/bbl, a NYMEX price of US$2.46/Mcf, an AECO price of $2.00/GJ and a USD/CDN exchange rate of 1.32. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this 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

ENERPLUS 2016 Q2 REPORT 25

those anticipated in such forward-looking information including, without limitation: continued low commodity prices environment or further decline of 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 and contingencies described under "Risk Factors and Risk Management" in the annual MD&A and in our other public filings).

The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

26 ENERPLUS 2016 Q2 REPORT

STATEMENTS

Condensed Consolidated Balance Sheets

(CDN$ thousands) unaudited		Note		June 30, 2016			December 31, 2015

Assets
Current Assets
	Cash		$	49,172		$	7,498
	Accounts receivable	3		102,990			132,156
	Deferred financial assets	15		14,228			71,438
	Other current assets			9,297			9,953

				175,687			221,045

Property, plant and equipment:
	Oil and natural gas properties (full cost method)	4		780,053			1,166,587
	Other capital assets, net	4		14,996			19,686

	Property, plant and equipment			795,049			1,186,273

Goodwill				645,420			657,831
Deferred income tax asset		13		186,667			516,085

Total Assets			$	1,802,823		$	2,581,234

Liabilities
Current liabilities
	Accounts payable	6	$	169,754		$	239,950
	Dividends payable			2,405			6,196
	Current portion of long-term debt	7		28,620			–
	Deferred financial liabilities	15		9,610			4,100

				210,389			250,246

Deferred financial liabilities		15		7,868			3,193
Long-term debt		7		694,699			1,223,682
Asset retirement obligation		8		188,207			206,359

				890,774			1,433,234

Total Liabilities				1,101,163			1,683,480

Shareholders' Equity
	Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2016 – 240 million shares December 31, 2015 – 206 million shares	14		3,365,962			3,133,524
	Paid-in capital			55,589			56,176
	Accumulated deficit			(3,057,849	)		(2,694,618	)
	Accumulated other comprehensive income/(loss)			337,958			402,672

				701,660			897,754

Total Liabilities & Equity			$	1,802,823		$	2,581,234

Contingencies		16

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

ENERPLUS 2016 Q2 REPORT 27

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

		Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) unaudited	Note		2016			2015			2016			2015

Revenues
Oil and natural gas sales, net of royalties	9	$	174,330		$	251,730		$	316,991		$	456,690
Commodity derivative instruments gain/(loss)	15		(21,907	)		(19,751	)		(8,443	)		30,647

			152,423			231,979			308,548			487,337

Expenses
Operating			60,540			76,744			133,130			164,471
Transportation			24,495			28,018			50,213			54,501
Production taxes			8,541			14,220			15,977			25,033
General and administrative	10		19,244			24,262			41,697			56,342
Depletion, depreciation and accretion			82,322			137,403			173,483			269,753
Asset impairment	5		148,679			497,247			194,856			764,858
Interest	11		10,634			16,121			25,350			33,154
Foreign exchange (gain)/loss	12		383			(27,656	)		(54,025	)		76,546
Gain on divestment of assets	4		(74,700	)		–			(219,800	)		–
Gain on prepayment of senior notes	7		(12,152	)		–			(19,270	)		–
Other expense/(income)			(82	)		(85	)		(242	)		8,527

			267,904			766,274			341,369			1,453,185

Income/(Loss) before taxes			(115,481	)		(534,295	)		(32,821	)		(965,848	)
Current income tax expense/(recovery)	13		(227	)		(102	)		(386	)		(39	)
Deferred income tax expense/(recovery)	13		53,300			(221,649	)		309,785			(360,059	)

Net Income/(Loss)		$	(168,554	)	$	(312,544	)	$	(342,220	)	$	(605,750	)

Other Comprehensive Income/(Loss)
Change in cumulative translation adjustment			1,654			(30,490	)		(64,714	)		146,269

Other Comprehensive Income/(Loss)			1,654			(30,490	)		(64,714	)		146,269

Total Comprehensive Income/(Loss)		$	(166,900	)	$	(343,034	)	$	(406,934	)	$	(459,481	)

Net income/(Loss) per share
Basic	14	$	(0.77	)	$	(1.52	)	$	(1.61	)	$	(2.94	)
Diluted	14	$	(0.77	)	$	(1.52	)	$	(1.61	)	$	(2.94	)

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

28 ENERPLUS 2016 Q2 REPORT

Condensed Consolidated Statements of Changes
in Shareholders' Equity

Six months ended June 30 (CDN$ thousands) unaudited		2016			2015

Share Capital
Balance, beginning of year	$	3,133,524		$	3,120,002
Issue of shares (net of issue costs)		223,031			–
Stock Option Plan – cash		–			3,205
Share-based compensation – settled		9,407			3,094
Stock Option Plan – exercised		–			267

Balance, end of period	$	3,365,962		$	3,126,568

Paid-in Capital
Balance, beginning of year	$	56,176		$	46,906
Share-based compensation – settled		(9,407	)		(3,094	)
Stock Option Plan – exercised		–			(267	)
Share-based compensation – non-cash		8,820			9,561

Balance, end of period	$	55,589		$	53,106

Accumulated Deficit
Balance, beginning of year	$	(2,694,618	)	$	(1,039,260	)
Net income/(loss)		(342,220	)		(605,750	)
Dividends		(21,011	)		(78,294	)

Balance, end of period	$	(3,057,849	)	$	(1,723,304	)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of year	$	402,672		$	95,478
Change in cumulative translation adjustment		(64,714	)		146,269

Balance, end of period	$	337,958		$	241,747

Total Shareholders' Equity	$	701,660		$	1,698,117

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

ENERPLUS 2016 Q2 REPORT 29

Condensed Consolidated Statements of Cash Flows

			Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) unaudited		Note		2016			2015			2016			2015

Operating Activities
Net income/(loss)			$	(168,554	)	$	(312,544	)	$	(342,220	)	$	(605,750	)
Non-cash items add/(deduct):
	Depletion, depreciation and accretion			82,322			137,403			173,483			269,753
	Asset impairment	5		148,679			497,247			194,856			764,858
	Changes in fair value of derivative instruments	15		41,060			73,738			67,395			161,237
	Deferred income tax expense/(recovery)	13		53,300			(221,649	)		309,785			(360,059	)
	Foreign exchange (gain)/loss on debt and working capital	12		131			(18,590	)		(56,027	)		69,424
	Share-based compensation	14		5,391			4,591			8,820			9,561
	Amortization of debt issue costs	11		570			240			752			480
Gain on divestment of assets		4		(74,700	)		–			(219,800	)		–
Gain on prepayment of senior notes		7		(12,152	)		–			(19,270	)		–
Derivative settlement of foreign exchange swaps				–			–			–			(39,904	)
Asset retirement obligation expenditures		8		(750	)		(2,569	)		(3,204	)		(6,459	)
Changes in non-cash operating working capital		17		(13,410	)		(22,771	)		17,064			3,051

Cash flow from/(used in) operating activities				61,887			135,096			131,634			266,192

Financing Activities
Proceeds from the issuance of shares		14		220,410			634			220,410			3,205
Cash dividends		14		(6,547	)		(30,935	)		(21,011	)		(78,294	)
Increase/(decrease) in bank credit facility				(150,073	)		(45,386	)		(79,223	)		434
Proceeds/(repayment) of senior notes		7		(109,371	)		(88,897	)		(335,400	)		(88,897	)
Derivative settlement of foreign exchange swaps				–			–			–			39,904
Changes in non-cash financing working capital				334			(15	)		(3,791	)		(8,222	)

Cash flow from/(used in) financing activities				(45,247	)		(164,599	)		(219,015	)		(131,870	)

Investing Activities
Capital and office expenditures				(48,206	)		(149,439	)		(91,498	)		(317,327	)
Property and land acquisitions				(343	)		1,011			(3,897	)		1,247
Property divestments		4		92,735			187,801			280,503			191,513
Changes in non-cash investing working capital				(11,909	)		(12,148	)		(54,035	)		(11,217	)

Cash flow from/(used in) investing activities				32,277			27,225			131,073			(135,784	)

Effect of exchange rate changes on cash				(1,026	)		677			(2,018	)		428

Change in cash				47,891			(1,601	)		41,674			(1,034	)
Cash, beginning of period				1,281			2,603			7,498			2,036

Cash, end of period			$	49,172		$	1,002		$	49,172		$	1,002

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

30 ENERPLUS 2016 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. The interim Consolidated Financial Statements were authorized for issue by the Board of Directors on August 4, 2016.

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, 2016 and the 2015 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' audited Consolidated Financial Statements as of December 31, 2015. There are no differences in the use of estimates or judgments between these interim Consolidated Financial Statements and the audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2015.

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.

3) ACCOUNTS RECEIVABLE

($ thousands)		June 30, 2016			December 31, 2015

Accrued receivables	$	85,367		$	91,378
Accounts receivable – trade		19,523			22,615
Current income tax receivable		1,488			21,410
Allowance for doubtful accounts		(3,388	)		(3,247	)

Total accounts receivable	$	102,990		$	132,156

4) PROPERTY, PLANT AND EQUIPMENT ("PP&E")

As at June 30, 2016 ($ thousands)		Cost		Accumulated Depletion, Depreciation, and Impairment			Net Book Value

Oil and natural gas properties	$	13,204,112	$	(12,424,059	)	$	780,053
Other capital assets		104,155		(89,159	)		14,996

Total PP&E	$	13,308,267	$	(12,513,218	)	$	795,049

As at December 31, 2015 ($ thousands)		Cost		Accumulated Depletion, Depreciation, and Impairment			Net Book Value

Oil and natural gas properties	$	13,541,670	$	(12,375,083	)	$	1,166,587
Other capital assets		105,124		(85,438	)		19,686

Total PP&E	$	13,646,794	$	(12,460,521	)	$	1,186,273

ENERPLUS 2016 Q2 REPORT 31

During the three and six months ended June 30, 2016, Enerplus disposed of certain Canadian properties for proceeds of $92.7 million and $280.5 million, respectively, which resulted in gains on asset divestments of $74.7 million and $219.8 million, respectively (2015 – nil and nil, respectively).

Under full cost accounting rules, divestitures of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre's capitalized costs and proved reserves, then a gain or loss must be recognized.

5) ASSET IMPAIRMENT

		Three months ended June 30,				Six months ended June 30,
($ thousands)			2016		2015		2016		2015

Oil and natural gas properties:
	Canada cost centre	$	34,200	$	28,100	$	34,200	$	28,100
	U.S. cost centre		114,479		469,147		160,656		736,758

Impairment expense		$	148,679	$	497,247	$	194,856	$	764,858

The impairments for the three and six months ended June 30, 2016 were due to lower 12-month average trailing crude oil and natural gas prices.

The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus' ceiling tests from June 30, 2015 through June 30, 2016:

Period		WTI Crude Oil US$/bbl	Exchange Rate US$/CDN$		Edm Light Crude CDN$/bbl		U.S. Henry Hub Gas US$/Mcf		AECO Natural Gas Spot CDN$/Mcf

Q2 2016	$	43.12	1.32	$	53.16	$	2.25	$	2.14
Q1 2016		46.26	1.32		56.97		2.41		2.47
Q4 2015		50.28	1.27		59.38		2.58		2.69
Q3 2015		59.21	1.22		66.51		3.08		3.00
Q2 2015		71.75	1.16		75.83		3.42		3.33

6) ACCOUNTS PAYABLE

($ thousands)		June 30, 2016		December 31, 2015

Accrued payables	$	92,806	$	167,253
Accounts payable – trade		76,948		72,697

Total accounts payable	$	169,754	$	239,950

7) DEBT

($ thousands)			June 30, 2016		December 31, 2015

Current:
	Senior notes	$	28,620	$	–

			28,620		–

Long-term:
	Bank credit facility	$	–	$	86,543
	Senior notes		694,699		1,137,139

			694,699		1,223,682

Total debt		$	723,319	$	1,223,682

32 ENERPLUS 2016 Q2 REPORT

For the three and six months ended June 30, 2016, Enerplus has repurchased US$95 million and US$267 million, respectively, in outstanding senior notes at a discount, resulting in gains of $12.2 million and $19.3 million, respectively. These repurchases have resulted in total payments of $109.4 million and $335.4 million for the three and six months ended June 30, 2016.

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

Issue Date

Interest Payment Dates

Principal Repayment

Coupon
Rate

Original
Principal
($ thousands)

Remaining
Principal
($ thousands)

CDN$ Carrying
Value
($ 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

136,534

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2019

4.34%

CDN$30,000

30,000

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

26,018

May 15, 2012

May 15 and Nov 15

5 equal annual installments
beginning May 15, 2020

4.40%

US$355,000

US$298,000

387,668

June 18, 2009

June 18 and Dec 18

5 equal annual installments
beginning June 18, 2017

7.97%

US$225,000

US$110,000

143,099

Total carrying value

723,319

8) ASSET RETIREMENT OBLIGATION

Enerplus has estimated the present value of its asset retirement obligation to be $188.2 million at June 30, 2016 compared to $206.4 million at December 31, 2015 based on a total undiscounted liability of $472.4 million and $556.4 million, respectively. The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.90% (December 31, 2015 – 5.91%).

($ thousands)		Six months ended June 30, 2016			Year ended December 31, 2015

Balance, beginning of year	$	206,359		$	288,692
Change in estimates		1,819			(35,386	)
Property acquisitions and development activity		240			761
Divestments		(22,648	)		(48,748	)
Settlements		(3,204	)		(14,935	)
Accretion expense		5,641			15,975

Balance, end of period	$	188,207		$	206,359

9) OIL AND NATURAL GAS SALES

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2016			2015			2016			2015

Oil and natural gas sales	$	212,741		$	298,433		$	383,164		$	542,510
Royalties(1)		(38,411	)		(46,703	)		(66,173	)		(85,820	)

Oil and natural gas sales, net of royalties	$	174,330		$	251,730		$	316,991		$	456,690

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

10) GENERAL AND ADMINISTRATIVE EXPENSE

	Three months ended June 30,				Six months ended June 30,
($ thousands)		2016		2015		2016		2015

General and administrative expense	$	14,600	$	19,872	$	33,026	$	41,307
Share-based compensation expense		4,644		4,390		8,671		15,035

General and administrative expense	$	19,244	$	24,262	$	41,697	$	56,342

ENERPLUS 2016 Q2 REPORT 33

11) INTEREST EXPENSE

		Three months ended June 30,				Six months ended June 30,
($ thousands)			2016		2015		2016		2015

Realized:
	Interest on bank debt and senior notes	$	10,064	$	15,881	$	24,598	$	32,674
Unrealized:
	Amortization of debt issue costs		570		240		752		480

Interest expense		$	10,634	$	16,121	$	25,350	$	33,154

12) FOREIGN EXCHANGE

		Three months ended June 30,					Six months ended June 30,
($ thousands)			2016		2015			2016			2015

Realized:
	Foreign exchange (gain)/loss	$	252	$	8,402		$	2,002		$	(27,172	)
Unrealized:
	Translation of U.S. dollar debt and working capital (gain)/loss		131		(18,590	)		(56,027	)		69,424
	Foreign exchange derivatives (gain)/loss		–		(17,468	)		–			34,294

Foreign exchange (gain)/loss		$	383	$	(27,656	)	$	(54,025	)	$	76,546

13) INCOME TAXES

Enerplus' provision for income tax is as follows:

		Three months ended June 30,						Six months ended June 30,
($ thousands)			2016			2015			2016			2015

Current tax expense/(recovery)
	Canada	$	(366	)	$	(400	)	$	(669	)	$	(400	)
	United States		139			298			283			361

Current tax expense/(recovery)			(227	)		(102	)		(386	)		(39	)

Deferred tax expense/(recovery)
	Canada	$	21,069		$	(27,676	)	$	33,915		$	(36,939	)
	United States		32,231			(193,973	)		275,870			(323,120	)

Deferred tax expense/(recovery)			53,300			(221,649	)		309,785			(360,059	)

Income tax expense/(recovery)		$	53,073		$	(221,751	)	$	309,399		$	(360,098	)

The difference between expected income taxes based on the statutory income tax rate and the effective income tax rate for the current and prior period is impacted by the following: expected annual earnings, recognition of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, the reversal or recognition of previously recognized or unrecognized deferred tax assets, non-taxable portions of capital gains and losses, and non-deductible share-based compensation. Enerplus recorded valuation allowances of $105.0 million and $363.5 million as at the three and six month periods ended June 30, 2016, respectively (2015 – nil and nil, respectively).

34 ENERPLUS 2016 Q2 REPORT

14) SHAREHOLDERS' EQUITY

a) Share Capital

		Six months ended June 30,				Year ended December 31,

		2016				2015

Authorized unlimited number of common shares Issued: (thousands)		Shares		Amount		Shares		Amount

Balance, beginning of year		206,539	$	3,133,524		205,732	$	3,120,002
Issued for cash:
	Stock Option Plan	–		–		234		3,205
	Issue of shares	33,350		230,115		–		–
	Share issue costs (net of tax of $2,620)	–		(7,084	)	–		–
Non-cash:
	Share-based compensation – settled	594		9,407		573		10,050
	Stock Option Plan – exercised	–		–		–		267

Balance, end of period		240,483	$	3,365,962		206,539	$	3,133,524

Dividends declared to shareholders for the three and six months ended June 30, 2016 were $6.5 million and $21.0 million, respectively (2015 – $30.9 million and $78.3 million, respectively).

On May 31, 2016, Enerplus issued 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230,115,000 ($220,410,400 net of issue costs).

At the Company's Annual General Meeting on May 6, 2016, the Shareholders of the Company approved a reduction in Enerplus' legal stated capital to $1 per share to be reflected in the contributed surplus account of the Company. This transaction does not result in an adjustment to the financial statements under U.S. GAAP.

b) Share-based Compensation

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

		Three months ended June 30,						Six months ended June 30,
($ thousands)			2016			2015			2016			2015

Cash:
	Long-term incentive plans expense	$	773		$	(1,233	)	$	1,506		$	6,041
Non-cash:
	Long-term incentive plans and stock option expense		5,391			4,591			8,820			9,561
	Equity swap (gain)/loss		(1,520	)		1,032			(1,655	)		(567	)

Share-based compensation expense		$	4,644		$	4,390		$	8,671		$	15,035

i) Long-term Incentive ("LTI") Plans

In 2014, the Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") plans were amended such that grants under the plans are settled through the issuance of treasury shares. The amendment was effective beginning with our grant in March of 2014 and any prior grants were settled in cash. The final cash-settled PSU and RSU grants were settled in December, 2015 and March, 2016, respectively. The Company's Director Share Units ("DSU") continue to be granted as cash-settled awards.

ENERPLUS 2016 Q2 REPORT 35

The following table summarizes the PSU, RSU and DSU activity for the six months ended June 30, 2016:

For the six months ended June 30, 2016	Cash-settled LTI plans			Equity-settled LTI plans
(thousands of units)	RSU		DSU	PSU		RSU		Total

Balance, beginning of year	92		166	1,222		1,627		3,107
Granted	–		134	1,417		1,987		3,538
Vested	(89	)	–	(9	)	(594	)	(692	)
Forfeited	(3	)	–	(88	)	(202	)	(293	)

Balance, end of period	–		300	2,542		2,818		5,660

Cash-settled LTI Plans

For the three and six months ended June 30, 2016, the Company recorded cash share-based compensation of $0.8 million and $1.5 million, respectively (June 30, 2015 – recovery of $1.2 million and expense of $6.0 million). For the three and six months ended June 30, 2016 the Company made cash payments of nil and $2.7 million, respectively, related to its cash-settled plans (June 30, 2015 – nil and $5.6 million).

As of June 30, 2016, a liability of $2.6 million (December 31, 2015 – $2.3 million) with respect to the DSU plan has been recorded to Accounts Payable on the Consolidated Balance Sheets.

Equity-settled LTI Plans

For the three and six months ended June 30, 2016 the Company recorded non-cash share-based compensation expense of $5.4 million and $8.8 million, respectively (2015 – $4.6 million and $9.6 million, respectively).

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

At June 30, 2016 ($ thousands, except for years)		PSU(1)		RSU		Total

Cumulative recognized share-based compensation expense	$	9,403	$	11,219	$	20,622
Unrecognized share-based compensation expense		8,861		9,241		18,102

Fair value	$	18,264	$	20,460	$	38,724

Weighted-average remaining contractual term (years)		1.9		1.5

(1): Includes estimated performance multipliers.

ii) Stock Option Plan

The Company did not grant any stock options for the three and six months ended June 30, 2016. At June 30, 2016 all stock options are fully vested and any related non-cash share-based compensation expense has been fully recognized.

The following table summarizes the stock option plan activity for the period ended June 30, 2016:

Period ended June 30, 2016		Number of Options (thousands)			Weighted Average Exercise Price

Options outstanding, beginning of year		7,580		$	18.49
	Forfeited	(1,070	)		18.76

Options outstanding, end of period		6,510		$	18.45

Options exercisable, end of period		6,510		$	18.45

At June 30, 2016, Enerplus had 6,510,000 options that were exercisable at a weighted average reduced exercise price of $18.45 with a weighted average remaining contractual term of 3.0 years, giving an aggregate intrinsic value of nil (2015 – nil). The intrinsic value of options exercised for both the three and six months ended June 30, 2016 was nil (June 30, 2015 – $0.1 million and $0.2 million, respectively).

36 ENERPLUS 2016 Q2 REPORT

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)			2016			2015			2016			2015

Net income/(loss)		$	(168,554	)	$	(312,544	)	$	(342,220	)	$	(605,750	)
Weighted average shares outstanding – Basic			218,128			206,208			212,420			206,028
Dilutive impact of share-based compensation(1)			–			–			–			–

Weighted average shares outstanding – Diluted			218,128			206,208			212,420			206,028

Net income/(loss) per share
	Basic	$	(0.77	)	$	(1.52	)	$	(1.61	)	$	(2.94	)
	Diluted(1)	$	(0.77	)	$	(1.52	)	$	(1.61	)	$	(2.94	)

(1): For the three and six months ended June 30, 2016 the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.

15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At June 30, 2016 the carrying value of cash, accounts receivable, accounts payable, dividends payable and bank credit facilities approximated their fair value due to the short-term maturity of the instruments.

At June 30, 2016 senior notes had a carrying value of $723.3 million and a fair value of $791.9 million (December 31, 2015 – $1,137.2 million and $1,220.8 million, respectively).

There were no transfers between fair value hierarchy levels during the period.

b) Derivative Financial Instruments

The deferred financial assets and liabilities on the 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, 2016 and 2015:

		Three months ended June 30,						Six months ended June 30,
Gain/(Loss) ($ thousands)			2016			2015			2016			2015		Income Statement Presentation

Foreign Exchange Derivatives		$	–		$	17,468		$	–		$	(34,294	)	Foreign exchange
Electricity Swaps			885			2,642			577			1,715		Operating expense
Equity Swaps			1,520			(1,032	)		1,655			567		General and administrative expense
Commodity Derivative Instruments:
	Oil		(27,144	)		(71,085	)		(58,420	)		(107,044	)	Commodity derivative instruments
	Gas		(16,321	)		(21,731	)		(11,207	)		(22,181	)

Total		$	(41,060	)	$	(73,738	)	$	(67,395	)	$	(161,237	)

The following table summarizes the income statement effects of Enerplus' commodity derivative instruments:

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2016			2015			2016			2015

Change in fair value gain/(loss)	$	(43,465	)	$	(92,816	)	$	(69,627	)	$	(129,225	)
Net realized cash gain/(loss)		21,558			73,065			61,184			159,872

Commodity derivative instruments gain/(loss)	$	(21,907	)	$	(19,751	)	$	(8,443	)	$	30,647

ENERPLUS 2016 Q2 REPORT 37

The following table summarizes the fair values at the respective period ends:

		June 30, 2016						December 31, 2015
		Assets		Liabilities				Assets		Liabilities
($ thousands)			Current		Current		Long-term		Current		Current		Long-term

Electricity Swaps		$	–	$	1,199	$	–	$	–	$	1,776	$	–
Equity Swaps			–		2,580		1,282		–		2,324		3,193
Commodity Derivative Instruments:
	Oil		14,228		–		5,251		67,397		–		–
	Gas		–		5,831		1,335		4,041		–		–

Total		$	14,228	$	9,610	$	7,868	$	71,438	$	4,100	$	3,193

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 derivative 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.

The following tables summarize the Corporation's price risk management positions at July 22, 2016:

Crude Oil Instruments:

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

Jul 1, 2016 – Dec 31, 2016
WTI Purchased Put	12,000	57.82
WTI Sold Call	12,000	71.75
WTI Sold Put	12,000	45.09
WCS Differential Swap	3,000	(14.03	)
MSW Differential Swap	1,000	(3.50	)
Jan 1, 2017 – Dec 31, 2017
WTI Purchased Put	12,000	50.00
WTI Sold Call	12,000	60.50
WTI Sold Put	12,000	38.59

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

38 ENERPLUS 2016 Q2 REPORT

Natural Gas Instruments:

Instrument Type(1)	MMcf/day	US$/Mcf

Jul 1, 2016 – Oct 31, 2016
NYMEX Swap	50.0	2.53
NYMEX Purchased Put	25.0	3.00
NYMEX Sold Call	25.0	3.75
NYMEX Sold Put	25.0	2.50
Nov 1, 2016 – Dec 31, 2016
NYMEX Swap	25.0	2.48
NYMEX Purchased Put	25.0	3.00
NYMEX Sold Call	25.0	3.75
NYMEX Sold Put	25.0	2.50
Jan 1, 2017 – Dec 31, 2017
NYMEX Purchased Put	45.0	2.72
NYMEX Sold Call	45.0	3.37
NYMEX Sold Put	45.0	2.03

(1): Transactions with a common term have been aggregated and presented at a weighted average price/Mcf.

Electricity Instruments:

Instrument Type	MWh	CDN$/MWh

Jul 1, 2016 – Dec 31, 2016
AESO Power Swap(1)	15.0	46.60
Jan 1, 2017 – Dec 31, 2017
AESO Power Swap(1)	6.0	44.38

(1): Alberta Electrical System Operator ("AESO") fixed pricing.

Physical Contracts:

Instrument Type	MMcf/day	US$/Mcf

Jul 1, 2016 – Oct 31, 2016	21.4	(0.68	)
AECO-NYMEX Basis
Nov 1, 2016 – Oct 31, 2017	80.0	(0.65	)
AECO-NYMEX Basis
Nov 1, 2017 – Oct 31, 2018	80.0	(0.65	)
AECO-NYMEX Basis
Nov 1, 2018 – Oct 31, 2019	80.0	(0.64	)
AECO-NYMEX Basis

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes 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, 2016 Enerplus did not have any foreign exchange derivatives outstanding.

Interest Rate Risk:

As of June 30, 2016 all of Enerplus' debt was based on fixed interest rates, and Enerplus had no interest rate derivatives outstanding.

ENERPLUS 2016 Q2 REPORT 39

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing between 2016 and 2018 and has effectively fixed the figure settlement cost on 470,000 shares at weighted average price of $16.89 per share.

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 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 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, 2016 approximately 50% of Enerplus' marketing receivables were with companies considered investment grade.

At June 30, 2016 approximately $2.1 million or 2% of Enerplus' total accounts receivable were aged over 120 days and considered past due. The majority of these accounts are due from various joint venture partners. 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. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectable the account is written off with a corresponding charge to the allowance account. Enerplus' allowance for doubtful accounts balance at June 30, 2016 was $3.4 million (December 31, 2015 – $3.2 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 shareholders' capital. Enerplus' objective is to provide adequate short and longer 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, access to capital markets, as well as acquisition and divestment activity.

At June 30, 2016 Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

16) CONTINGENCIES

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.

40 ENERPLUS 2016 Q2 REPORT

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes In Non-Cash Operating Working Capital

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2016			2015			2016			2015

Accounts receivable	$	288		$	(5,371	)	$	29,640		$	18,696
Other current assets		(3,426	)		(10,079	)		(96	)		(14,877	)
Accounts payable		(10,272	)		(7,321	)		(12,480	)		(768	)

	$	(13,410	)	$	(22,771	)	$	17,064		$	3,051

b) Other

	Three months ended June 30,					Six months ended June 30,
($ thousands)		2016			2015		2016			2015

Income taxes paid/(received)	$	(17,194	)	$	148	$	(19,118	)	$	(19,197	)
Interest paid		17,832			25,936		27,638			32,418

ENERPLUS 2016 Q2 REPORT 41

BOARD OF DIRECTORS

Elliott Pew⁽¹⁾⁽²⁾
Corporate Director
Boerne, Texas

David H. Barr^(9)(12)
Corporate Director
The Woodlands, Texas

Michael R. Culbert^(3)(5)(9)
President & CEO
Progress Energy Canada Ltd.
Calgary, Alberta

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
Calgary, Alberta

Hilary A. Foulkes^{(5)(7)(9)(11)}
Corporate Director
Calgary, Alberta

Robert B. Hodgins⁽³⁾⁽⁶⁾
Corporate Director
Calgary, Alberta

Susan M. MacKenzie⁽⁷⁾⁽¹⁰⁾⁽¹¹⁾
Corporate Director
Calgary, Alberta

Glen D. Roane⁽⁴⁾⁽⁵⁾
Corporate Director
Canmore, Alberta

Sheldon B. Steeves⁽⁵⁾⁽⁸⁾
Corporate Director
Calgary, Alberta

OFFICERS

ENERPLUS CORPORATION

Ian C. Dundas
President & Chief Executive Officer

Ray J. Daniels
Senior Vice President, Operations

Jodine J. Jenson Labrie
Senior Vice President & Chief Financial Officer

Eric G. Le Dain
Senior Vice President, Corporate Development, Commercial

Nathan D. Fisher
Vice President, U.S. Development & Geosciences

Daniel J. Fitzgerald
Vice President, Business Development

John E. Hoffman
Vice President, Canadian Operations

David A. McCoy
Vice President, General Counsel & Corporate Secretary

Edward L. McLaughlin
President, U.S. Operations

Lisa M. Ower
Vice President, People & Culture

Shaina B. Morihira
Corporate Controller, Finance

(1): Chairman of the Board
(2): Ex-Officio member of all Committees of the Board
(3): Member of the Corporate Governance & Nominating Committee
(4): Chair of the Corporate Governance & Nominating Committee
(5): Member of the Audit & Risk Management Committee
(6): Chair of the Audit & Risk Management Committee
(7): Member of the Reserves Committee
(8): Chair of the Reserves Committee
(9): Member of the Compensation & Human Resources Committee
(10): Chair of the Compensation & Human Resources Committee
(11): Member of the Safety & Social Responsibility Committee
(12): Chair of the Safety & Social Responsibility Committee

42 ENERPLUS 2016 Q2 REPORT

CORPORATE INFORMATION

OPERATING COMPANIES OWNED BY ENERPLUS CORPORATION

Enerplus Resources (USA) Corporation

LEGAL COUNSEL

Blake, Cassels & Graydon LLP
Calgary, Alberta

AUDITORS

Deloitte LLP
Calgary, Alberta

TRANSFER AGENT

Computershare Trust Company of Canada
Calgary, Alberta
Toll free: 1.866.921.0978

U.S. CO-TRANSFER AGENT

Computershare Trust Company, N.A.
Golden, Colorado

INDEPENDENT RESERVE ENGINEERS

McDaniel & Associates Consultants Ltd.
Calgary, Alberta

Netherland, Sewell & Associates, Inc.
Dallas, Texas

STOCK EXCHANGE LISTINGS AND TRADING SYMBOLS

Toronto Stock Exchange: ERF
New York Stock Exchange: ERF

U.S.OFFICE

950 17^th Street, Suite 2200
Denver, Colorado 80202

Telephone: 720.279.5500
Fax: 720.279.5550

ABBREVIATIONS
AECO		a reference to the physical storage and trading hub on the TransCanada Alberta Transmission System (NOVA) which is the delivery point for the various benchmark Alberta Index prices
bbl(s)/day		barrel(s) per day, with each barrel representing 34.972 Imperial gallons or 42 U.S. gallons
Bcf		billion cubic feet
Bcfe		billion cubic feet equivalent
BOE		barrels of oil equivalent
Brent		crude oil sourced from the North Sea, the benchmark for global oil trading quoted in $US dollars.
LTI		long-term incentive
Mbbls		thousand barrels
MBOE		thousand barrels of oil equivalent
Mcf		thousand cubic feet
Mcfe		thousand cubic feet equivalent
MMbbl(s)		million barrels
MMBOE		million barrels of oil equivalent
MMBtu		million British Thermal Units
MMcf		million cubic feet
MSW		mixed sweet blend
MWh		megawatt hour(s) of electricity
NGLs		natural gas liquids
NYMEX		New York Mercantile Exchange, the benchmark for North American natural gas pricing
OCI		other comprehensive income
SBC		share based compensation
SDP		stock dividend program
U.S. GAAP		accounting principles generally accepted in the United States of America
WCS		Western Canadian Select at Hardisty, Alberta, the benchmark for Western Canadian heavy oil pricing purposes
WTI		West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing

ENERPLUS 2016 Q2 REPORT 43

Why invest in Enerplus?

Enerplus Corporation is a responsible developer of high quality crude oil and
natural gas assets in Canada and the United States, focused on providing
both growth and income to its shareholders.

QuickLinks

Exhibit 99.1

This regulatory filing also includes additional resources:
a2229288zenerplus_q2-report.pdf

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