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, 2015

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 — Management's Discussion and Analysis for the Second Quarter ended June 30, 2015

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Second Quarter ended June 30, 2015

EXHIBIT 99.3 — Certification of the Chief Executive Officer

EXHIBIT 99.4 — Certification of the Chief Financial Officer

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		ENERPLUS CORPORATION
		BY:		/s/ DAVID A. MCCOY David A. McCoy Vice President, General Counsel & Corporate Secretary

DATE: August 7, 2015

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EXHIBIT INDEX
SIGNATURE

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Exhibit 99.1

MD&A

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

The following discussion and analysis of financial results is dated August 6, 2015 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, 2015 and 2014 (the "Interim Financial Statements");
•: the audited consolidated financial statements of Enerplus as at December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012; and
•: our MD&A for the year ended December 31, 2014 (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" below 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 other 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 interest unless otherwise stated. Company interest is not a term defined in Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities 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.

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. The term netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating costs and transportation.

6 ENERPLUS 2015 Q2 REPORT

		Three months ended June 30,						Six months ended June 30,
Calculation of Netback ($ millions)			2015			2014			2015			2014

Oil and natural gas sales		$	298.4		$	504.5		$	542.5		$	999.6
Less:
	Royalties		(46.7	)		(89.6	)		(85.8	)		(176.9	)
	Production taxes		(14.2	)		(20.0	)		(25.0	)		(39.8	)
	Cash operating costs(1)		(79.3	)		(86.2	)		(166.2	)		(166.1	)
	Transportation		(28.0	)		(22.6	)		(54.5	)		(45.0	)

Netback before hedging		$	130.2		$	286.1		$	211.0		$	571.8
	Cash gains/(losses) on derivative instruments		73.1			(24.5	)		159.9			(39.9	)

Netback after hedging		$	203.3		$	261.6		$	370.9		$	531.9

(1): Operating costs adjusted to exclude non-cash gains on fixed price electricity swaps of $2.6 million and $1.7 million in the three and six months ended June 30, 2015 and $0.2 million in both the three and six months ended June 30, 2014.

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

	Three months ended June 30,					Six months ended June 30,
Reconciliation of Cash Flow from Operating Activities to Funds Flow ($ millions)		2015		2014			2015			2014

Cash flow from operating activities	$	135.0	$	228.5		$	266.2		$	368.9
Asset retirement obligation expenditures		2.6		4.2			6.5			8.5
Changes in non-cash operating working capital		22.8		(19.5	)		(3.1	)		56.3

Funds Flow	$	160.4	$	213.2		$	269.6		$	433.7

"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 12 months of funds flow. This measure is not equivalent to Debt to Earnings before Interest, Taxes, Depreciation and Amortization and other non-cash charges ("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.

	Three months ended June 30,				Six months ended June 30,
Calculation of Adjusted Payout Ratio ($ millions)		2015		2014		2015		2014

Cash dividends(1)	$	30.9	$	50.5	$	78.3	$	92.7
Capital and office expenditures		149.4		205.6		317.3		423.8

	$	180.3	$	256.1	$	395.6	$	516.5
Funds flow		160.4		213.2		269.6		433.7

Adjusted payout ratio (%)		112%		120%		147%		119%

(1): Cash dividends exclude stock dividend plan proceeds in 2014.

In addition, the Company uses certain financial measures within the "Overview" and "Liquidity and Capital Resources" sections 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 EBITDA", "Total Debt to EBITDA", "Total Debt to Capitalization", "maximum debt to consolidated present value of total proven reserves" and "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.

ENERPLUS 2015 Q2 REPORT 7

OVERVIEW

Our strong operational performance continued in the second quarter as we delivered production growth and met or exceeded all our guidance targets. As a result, we are increasing our 2015 production guidance and lowering our operating cost and general and administrative ("G&A") expense guidance by $0.65/BOE, combined. All other guidance targets are maintained.

Average daily production for the second quarter was 107,429 BOE/day, exceeding our annual average production guidance range of 97,000-103,000 BOE/day. Production increased approximately 6,600 BOE/day or 7% from the first quarter of 2015. The majority of the production growth was driven by our ongoing development in Fort Berthold, North Dakota, where production increased 26% or approximately 5,600 BOE/day compared to the first quarter. Natural gas production increased 6% from the prior quarter due to the ongoing development of our Canadian deep gas properties and well outperformance in the Marcellus. Based on our continued operational success, we are increasing our production guidance range to 100,000-104,000 BOE/day and expect approximately 44,000-46,000 bbls/day of crude oil and natural gas liquids.

We maintained a disciplined capital program with spending of $148.0 million in our core areas during the quarter and are on track to meet our annual capital spending guidance of $540.0 million.

Both operating costs and G&A expenses came in below guidance, at $76.7 million or $7.85/BOE and $19.9 million or $2.03/BOE, respectively. As a result of our continued focus on cost control and increased production target, we are decreasing our operating cost guidance to $9.25/BOE from $9.75/BOE and our G&A expense guidance to $2.25/BOE from $2.40/BOE, representing a combined decrease of $0.65/BOE.

Funds flow increased by 47% to $160.4 million from $109.2 million in the first quarter as a result of production growth and higher oil prices, along with the impact of one-time expenses experienced in the first quarter. Compared to the same period in 2014, funds flow decreased by approximately $52.8 million or 25% as oil and natural gas sales reflected the significant decline in commodity prices. Our hedging program provided additional revenue, generating gains of $73.1 million in the quarter compared to losses of $24.5 million in the same period of 2014.

Under U.S. GAAP, we recorded a net loss of $312.5 million for the quarter compared to net income of $40.0 million in the second quarter of 2014. The continued decline in the twelve month trailing average commodity price resulted in an asset impairment of $497.2 million in the quarter. Year to date, we have recorded cumulative asset impairments of $764.9 million. We expect the twelve month trailing prices used to calculate impairment charges in accordance with U.S. GAAP to decline further, which may lead to additional write-downs of our oil and natural gas properties in the second half of 2015.

Despite a decline in commodity prices during the first half of 2015 we remain in a strong financial position. At June 30, 2015 we were approximately 8% drawn on our $1.0 billion credit facility and had a conservative debt to funds flow ratio of 1.6x and senior debt to EBITDA ratio of 1.5x. After a US$10.8 million senior note repayment due in the fourth quarter of 2015 we will have no term debt principal repayments due until June of 2017. We have added significantly to our hedging program during the quarter and continue to expect our risk management program to protect our balance sheet and a portion of our funds flow in the second half of 2015 and into 2016.

RESULTS OF OPERATIONS

Production

Production for the second quarter totaled 107,429 BOE/day, exceeding our guidance range of 97,000-103,000 BOE/day and increasing 7% compared to 100,855 BOE/day in the first quarter of 2015. This increase was driven primarily by growth in our Fort Berthold production, which increased 26% or 5,600 BOE/day compared to the prior quarter. We brought on 9.2 net wells in Fort Berthold during the quarter compared to 3.6 net wells in the first quarter. Based on our decision to accelerate the completion of eight additional wells during the second half of 2015 we expect modest production growth in the region. Natural gas production increased by 6% from the prior quarter due to our ongoing development program in the Canadian Deep Basin as well as continued well outperformance in the Marcellus.

Production in the second quarter of 2015 increased by 3% from 103,987 BOE/day in the same period of 2014 primarily due to an increase in Fort Berthold crude oil production. Natural gas production remained relatively flat compared to the second quarter of 2014, with growth in our Marcellus and Canadian Deep Basin production offset by the divestment of non-core Canadian natural gas properties in the second half of 2014.

8 ENERPLUS 2015 Q2 REPORT

Our production mix was unchanged from the previous quarter with crude oil and natural gas liquids accounting for 43% of our total average daily production.

Average daily production volumes for the three and six months ended June 30, 2015 and 2014 are outlined below:

	Three months ended June 30,			Six months ended June 30,
Average Daily Production Volumes	2015	2014	% Change	2015	2014	% Change

Crude oil (bbls/day)	41,122	39,863	3%	40,243	38,817	4%
Natural gas liquids (bbls/day)	5,145	3,636	42%	4,444	3,450	29%
Natural gas (Mcf/day)	366,971	362,929	1%	356,836	354,906	1%

Total daily sales (BOE/day)	107,429	103,987	3%	104,160	101,418	3%

As a result of continued outperformance we are revising our average annual production guidance upwards to 100,000-104,000 BOE/day from our guidance of 97,000-103,000 BOE/day provided in June. We expect annual production to include 44,000-46,000 bbls/day of crude oil and natural gas liquids.

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 quarterly average prices from the second quarter of 2015 to the second quarter of 2014:

		Six months ended June 30,
Pricing (average for the period)			2015			2014			Q2 2015			Q1 2015			Q4 2014			Q3 2014			Q2 2014

Benchmarks
	WTI crude oil (US$/bbl)	$	53.29		$	100.84		$	57.94		$	48.64		$	73.15		$	97.17		$	102.99
	AECO natural gas – monthly index (CDN$/Mcf)		2.81			4.72			2.67			2.95			4.01			4.22			4.68
	AECO natural gas – daily index (CDN$/Mcf)		2.70			5.20			2.64			2.75			3.60			4.02			4.69
	NYMEX natural gas – last day (US$/Mcf)		2.81			4.80			2.64			2.98			4.00			4.06			4.67
	US/CDN exchange rate		1.24			1.10			1.23			1.24			1.14			1.09			1.09
Enerplus Selling Price(1)
	Crude oil (CDN$/bbl)	$	51.35		$	94.80		$	58.26		$	44.04		$	69.17		$	88.28		$	96.46
	Natural gas liquids (CDN$/bbl)		21.55			59.37			20.88			22.48			42.34			46.76			51.80
	Natural gas (CDN$/Mcf)		2.32			4.60			2.09			2.58			3.25			3.36			4.15

Average differentials
	MSW Edmonton – WTI (US$/bbl)	$	(4.93	)	$	(7.19	)	$	(3.06	)	$	(6.80	)	$	(6.36	)	$	(7.93	)	$	(6.13	)
	WCS Hardisty – WTI (US$/bbl)		(13.16	)		(21.59	)		(11.59	)		(14.73	)		(14.24	)		(20.18	)		(20.04	)
	Brent Futures (ICE) – WTI (US$/bbl)		6.10			7.97			5.63			6.58			3.85			6.26			6.75
	AECO monthly – NYMEX (US$/Mcf)		(0.54	)		(0.50	)		(0.47	)		(0.60	)		(0.47	)		(0.18	)		(0.38	)
Enerplus realized differentials(1)
	Canada crude oil – WTI (US$/bbl)	$	(14.13	)	$	(18.36	)	$	(12.50	)	$	(15.22	)	$	(12.17	)	$	(20.51	)	$	(16.77	)
	Canada natural gas – NYMEX (US$/Mcf)		(0.46	)		(0.25	)		(0.46	)		(0.46	)		(0.62	)		(0.29	)		(0.46	)
	Bakken crude oil – WTI (US$/bbl)		(10.05	)		(11.29	)		(9.30	)		(11.65	)		(12.15	)		(12.81	)		(12.81	)
	Marcellus natural gas – NYMEX (US$/Mcf)		(1.35	)		(1.19	)		(1.39	)		(1.32	)		(1.62	)		(1.70	)		(1.48	)

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

Crude Oil and Natural Gas Liquids

WTI crude oil prices increased by 19% versus the previous quarter to average US$57.94/bbl during the second quarter of 2015. Although crude oil inventories in the U.S. reached record levels of 491 million barrels in April, strong seasonal demand for gasoline and early indications of slowing crude oil production growth in the U.S. resulted in inventory levels falling and WTI prices trading over US$60/bbl. However, increasing concerns over the Chinese economy and its potential negative impact on crude oil demand growth, the nuclear agreement with Iran that will

ENERPLUS 2015 Q2 REPORT 9

eventually allow increased Iranian production to return to the market and the ongoing debt crisis in Greece all contributed to the decline of WTI to under US$50/bbl by mid-July.

The strength in WTI prices during the second quarter combined with improved realized crude oil differentials resulted in a 32% improvement in selling price for our crude oil compared to the previous quarter. Crude oil differentials in Canada strengthened considerably during the second quarter, due largely to scheduled oil sands maintenance and other unplanned outages from forest fires in Northern Alberta reducing production. As a result, WCS differentials to WTI narrowed by US$3.14/bbl to average US$11.59/bbl below WTI and light sweet crude oil differentials in Canada narrowed by US$3.74/bbl to average US$3.06/bbl below WTI. The strength in light sweet differentials helped support our Bakken differentials as well, which narrowed by US$2.35/bbl quarter over quarter to average US$9.30/bbl below WTI during the second quarter. We expect both heavy and light oil differentials in Canada and the U.S. to widen for the rest of the year relative to the second quarter, as production is stabilizing in the affected regions.

The decline in crude oil prices over the past twelve months and the level of natural gas liquids production across the continent continues to depress North American natural gas liquids prices, specifically propane. As propane production and inventories in Canada and the U.S. grow, it has resulted in negative benchmark prices for propane during May and June. However, stronger WTI prices during the quarter helped stabilize market prices for butanes and condensate, partially offsetting the weakness in propane prices. Our realized price for our natural gas liquids production fell by 7% quarter over quarter to average $20.88/bbl.

Natural Gas

Both AECO monthly index and NYMEX natural gas prices fell by 9% and 11%, respectively, versus the previous quarter due to continued high production and increased storage levels across the continent. U.S. dry gas production in June was approximately 3.0 Bcf/day higher than last year while U.S. storage levels ended the quarter in line with the five year average. Although production remains high, demand for natural gas fired power generation increased relative to previous years as natural gas prices were low enough to incentivize generators to switch from coal to natural gas as a fuel for power generation. This increased power demand, combined with higher than expected exports from the U.S. to Mexico, provided some price support by offsetting the continued strong North American production. However, even with the extra demand and normal weather, the strong production may push storage inventories to test the upper end of capacity levels by the end of October.

In Western Canada, there were ongoing service interruptions and restrictions in certain areas of the NOVA Gas Transmission Ltd. ("NGTL") pipeline system as TransCanada was required by the National Energy Board to carry out thorough safety inspections of smaller diameter pipelines. These restrictions, combined with other unplanned maintenance issues across the system, have caused many producers in Western Canada to curtail natural gas production. Overall, we have been able to limit the impact on Enerplus through holding firm transportation in our key areas and actively managing transportation shortfalls at affected locations. We had on average roughly 5 MMcfe/day of natural gas production temporarily curtailed during the quarter due to these restrictions. We anticipate the curtailment of transportation services to ease somewhat before the end of the year, however, the issue may persist into 2016 as further NGTL safety inspections are required.

Our overall realized sales price for natural gas fell by 19% compared to the previous quarter to average $2.09/Mcf. This is in line with the combination of weaker NYMEX pricing and continued weakness in the Marcellus producing region. While the average of spot market prices in Northeast Pennsylvania at the Transco Leidy and TGP Zone 4 Marcellus were roughly unchanged from the first quarter, outside of the northeast Pennsylvania producing region prices at Dominion South Point fell by 24% to average US$1.40/Mcf in the quarter. With approximately 37% of our Marcellus production tied to markets outside the northeast Pennsylvania producing region that all realized wider differentials to NYMEX versus the previous quarter, our overall realized discount to NYMEX for our Marcellus production widened by 5% or US$0.07/Mcf versus the first quarter to average US$1.39/Mcf.

Foreign Exchange

The Canadian dollar strengthened during the second quarter, increasing a modest 2% as a result of higher crude oil prices. Subsequent to the quarter, we saw the Canadian dollar fall to a six year low USD/CDN exchange rate of 1.30 following the Bank of Canada's decision to cut interest rates by 25 basis points and lower their forecasted economic growth for 2015. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices and therefore a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized sales. Because we report in Canadian dollars, the weaker Canadian dollar also increases our U.S. dollar denominated operating costs, capital spending and the principal and interest on our U.S. dollar denominated senior notes.

10 ENERPLUS 2015 Q2 REPORT

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. We continued to add to our commodity hedge position in both 2015 and 2016 as a result of the modest improvement in crude oil prices during the quarter along with our decision to accelerate the completions of eight additional North Dakota wells. For the second half of 2015 we have an average of 11,250 bbls/day of crude oil (approximately 35% of our expected crude oil production, net of royalties) hedged at an average floor price of US$84.58/bbl through a combination of swaps and three-way collar structures. In 2016 we have an average of 11,000 bbls/day of crude oil (approximately 34% of our expected crude oil production, net of royalties) hedged at an average floor price of US$64.35/bbl through a combination of swaps and three-way collar structures.

We continued to add to our NYMEX gas hedging program for 2015 and began hedging our 2016 gas production during the quarter. In the second half of 2015 we are swapped on an average of 128,370 Mcf/day (approximately 47% of our forecasted natural gas production, net of royalties) at an average price of US$3.82/Mcf. In 2016 we have 25,000 Mcf/day (approximately 9% of our forecasted natural gas production, net of royalties) hedged through three-way collars with an average floor price of US$3.00/Mcf.

The following is a summary of our financial contracts in place at July 22, 2015 expressed as a percentage of our anticipated net production volumes:

	WTI Crude Oil (US$/bbl)(1)								NYMEX Natural Gas (US$/Mcf)(1)
		Jul 1, 2015 – Sept 30, 2015		Oct 1, 2015 – Dec 31, 2015		Jan 1, 2016 – Jun 30, 2016		Jul 1, 2016 – Dec 31, 2016		Jul 1, 2015 – Sept 30, 2015		Oct 1, 2015 – Oct 31, 2015		Nov 1, 2015 – Dec 31, 2015		Jan 1, 2016 – Dec 31, 2016

Downside Protection – Swaps
Sold Swaps	$	93.86	$	82.10	$	64.28		–	$	3.73	$	3.85	$	4.04		–
%		25%		39%		9%		–		57%		42%		35%		–
Downside Protection – Collars
Sold Puts		–	$	48.00	$	50.13	$	49.34		–		–		–	$	2.50
%		–		6%		25%		34%		–		–		–		9%
Purchased Puts		–	$	63.00	$	64.38	$	64.35		–		–		–	$	3.00
%		–		6%		25%		34%		–		–		–		9%
Sold Calls		–	$	70.00	$	79.38	$	80.09		–		–		–	$	3.75
%		–		6%		25%		34%		–		–		–		9%
Upside Participation Collars
Sold Puts	$	62.23	$	62.23		–		–	$	3.25	$	3.25	$	3.25		–
%		13%		13%		–		–		2%		2%		2%		–
Purchased Calls	$	93.00	$	93.00		–		–	$	4.29	$	4.29	$	4.29		–
%		13%		13%		–		–		2%		2%		2%		–
Sold Calls		–		–		–		–	$	5.00	$	5.00	$	5.00		–
%		–		–		–		–		2%		2%		2%		–

(1): Based on weighted average price (before premiums), assumed average annual production of 100,000 – 104,000 BOE/day for 2015 and 2016, less royalties and production taxes of 21.0% in aggregate.

We have also entered into WCS and MSW differential swap positions to manage our exposure to Canadian crude oil differentials. At July 22, 2015, we have 4,000 bbls/day of WCS swapped at US$(16.61)/bbl and 1,000 bbls/day of MSW swapped at US$(3.50)/bbl in the second half of 2015 and 2,000 bbls/day of WCS swapped at US$(14.50)/bbl in 2016.

We have physically hedged a portion of our exposure to AECO differentials versus NYMEX prices through to October 2019. These basis transactions are intended to protect against weakening natural gas prices in Alberta as increased production from the Marcellus is expected to flow into Ontario and the U.S. Midwest over the coming years. There is also a risk of weaker AECO prices as a result of continued growth in natural gas production in advance of potential Canadian west coast liquefied natural gas exports.

ENERPLUS 2015 Q2 REPORT 11

The following table provides a summary of the physical AECO-NYMEX basis contracts we have in place at July 22, 2015:

	MMcf/day		US$/Mcf

Jul 1, 2015 – Oct 31, 2015	60.0	$	(0.65	)
AECO-NYMEX Basis
Nov 1, 2015 – Oct 31, 2016	60.0	$	(0.67	)
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

In 2014 we entered into foreign exchange collars on US$24 million per month to hedge a floor exchange rate on a portion of our U.S. dollar denominated oil and natural gas sales with upside participation in the event the Canadian dollar weakened. During the second quarter of 2015 we entered into U.S. dollar forward exchange contracts on US$6 million per month at an exchange rate of USD/CDN 1.20 to partially mitigate our losses on these collars. As of July 22, 2015, we effectively have US$18 million per month hedged for 2015 at an average USD/CDN floor of 1.1088, a ceiling of 1.1845 and a conditional ceiling of 1.1263. Under these contracts, if the monthly foreign exchange rate settles above the ceiling rate the conditional celling is used to determine the settlement amount.

ACCOUNTING FOR PRICE RISK MANAGEMENT

		Three months ended June 30,						Six months ended June 30,
Commodity Risk Management Gains/(Losses) ($ millions)			2015			2014			2015			2014

Cash gains/(losses):
	Crude oil	$	56.7		$	(21.2	)	$	127.2		$	(32.0	)
	Natural gas		16.4			(3.3	)		32.7			(7.9	)

Total cash gains/(losses)		$	73.1		$	(24.5	)	$	159.9		$	(39.9	)
Non-cash gains/(losses):
	Change in fair value – crude oil	$	(71.1	)	$	(24.8	)	$	(107.1	)	$	(34.2	)
	Change in fair value – natural gas		(21.8	)		5.3			(22.2	)		(2.6	)

Total non-cash gains/(losses)		$	(92.9	)	$	(19.5	)	$	(129.3	)	$	(36.8	)

Total gains/(losses)		$	(19.8	)	$	(44.0	)	$	30.6		$	(76.7	)

	Three months ended June 30,						Six months ended June 30,
(Per BOE)		2015			2014			2015			2014

Total cash gains/(losses)	$	7.47		$	(2.60	)	$	8.48		$	(2.17	)
Total non-cash gains/(losses)		(9.49	)		(2.06	)		(6.85	)		(2.01	)

Total gains/(losses)	$	(2.02	)	$	(4.66	)	$	1.63		$	(4.18	)

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. In comparison, during the second quarter of 2014 we realized cash losses of $21.2 million on our crude oil contracts and $3.3 million on our natural gas contracts. The cash gains in 2015 were due to contracts which provided floor protection above market prices, while cash losses in 2014 were a result of prices rising above our fixed price swap positions.

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 2015 the fair value of our crude oil and

12 ENERPLUS 2015 Q2 REPORT

natural gas contracts represented net gain positions of $60.1 million and $27.1 million, respectively. For the three and six months ended June 30, 2015 the change in the fair value of our crude oil contracts represented losses of $71.1 million and $107.1 million, respectively, and our natural gas contracts represented losses of $21.8 million and $22.2 million, respectively.

During the three and six months ended June 30, 2015 we recorded total cash losses on our foreign exchange collars of $7.1 million and $15.7 million, respectively. At June 30, 2015 the fair value of foreign exchange derivatives was a net loss of $12.5 million. See Note 15 for further information.

Revenues

	Three months ended June 30,						Six months ended June 30,
($ millions)		2015			2014			2015			2014

Oil and natural gas	$	298.4		$	504.5		$	542.5		$	999.6
Royalties		(46.7	)		(89.6	)		(85.8	)		(176.9	)

Oil and natural gas sales, net of royalties	$	251.7		$	414.9		$	456.7		$	822.7

Oil and natural gas revenues for the three and six months ended June 30, 2015 were $298.4 million and $542.5 million, respectively, compared to $504.5 million and $999.6 million for the same periods in 2014. The decrease in revenue was driven by the weak commodity price environment, which saw benchmark prices decline between 40% and 48% in the first half of 2015 compared to the same period in 2014.

Royalties and Production Taxes

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Royalties	$	46.7	$	89.6	$	85.8	$	176.9
Per BOE	$	4.78	$	9.47	$	4.55	$	9.64
Production taxes	$	14.2	$	20.0	$	25.0	$	39.8
Per BOE	$	1.45	$	2.11	$	1.33	$	2.17

Royalties and production taxes	$	60.9	$	109.6	$	110.8	$	216.7
Per BOE	$	6.23	$	11.58	$	5.88	$	11.81
Royalties and production taxes (% of oil and natural gas sales, before transportation)		20%		22%		20%		22%

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. During the three and six months ended June 30, 2015 royalties and production taxes decreased to $60.9 million and $110.8 million, respectively, from $109.6 million and $216.7 million for the same periods in 2014, primarily due to lower realized prices. Royalties and production taxes averaged 20% of oil and natural gas sales before transportation in the first half of 2015 compared to 22% for the same period in 2014.

We continue to expect an average royalty and production tax rate of 21% in 2015.

Operating Expenses

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Operating expenses	$	76.7	$	86.0	$	164.5	$	165.9
Per BOE	$	7.85	$	9.09	$	8.72	$	9.03

As of January 1, 2015 we have reclassified Marcellus gathering costs from operating expenses to transportation costs. These charges relate to pipeline costs paid to third parties to transport saleable natural gas from the lease to downstream points of sale. This is a presentation change

ENERPLUS 2015 Q2 REPORT 13

with no impact on our netback, funds flow or net income. All comparative periods have been presented to conform with the current period presentation.

Operating expenses continued to trend lower as a result of our cost saving initiatives. For the three and six months ended June 30, 2015 operating expenses were $76.7 million or $7.85/BOE and $164.5 million or $8.72/BOE, respectively, compared to $86.0 million or $9.09/BOE and $165.9 million or $9.03/BOE for the same periods in 2014. The decrease in operating costs during 2015 compared to 2014 was primarily due to realized cost savings in repairs and maintenance and well servicing, which were offset somewhat by the impact of a weaker Canadian dollar on our U.S. dollar denominated operating costs.

Based on our cost savings realized to date and our increased production guidance we are reducing our 2015 guidance for operating expenses to $9.25/BOE from $9.75/BOE. Although year to date operating costs are below our revised guidance, we anticipate an increase in operating costs during the second half of 2015 as a result of the seasonality of some spend and scheduled facility turnarounds.

Transportation Costs

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Transportation costs	$	28.0	$	22.6	$	54.5	$	45.0
Per BOE	$	2.87	$	2.39	$	2.89	$	2.45

As discussed previously in operating expenses, we have reclassified Marcellus gathering costs from operating expenses to transportation costs. This is a presentation change with no impact on our netback, funds flow or net income. All comparative periods have been presented to conform with the current period presentation.

For the three and six months ended June 30, 2015 transportation costs were $28.0 million or $2.87/BOE and $54.5 million or $2.89/BOE, respectively, compared to $22.6 million or $2.39/BOE and $45.0 million or $2.45/BOE for the same periods in 2014. The increase in transportation costs was due to higher U.S. production and the impact of a weakening Canadian dollar on our U.S. dollar denominated costs.

We are maintaining our transportation cost guidance of $3.00/BOE.

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. Certain prior period amounts have been reclassified to conform with current period presentations.

		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 costs		(11.27	)		(0.91	)		(8.12	)
	Transportation		(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

14 ENERPLUS 2015 Q2 REPORT

		Three months ended June 30, 2014
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			44,681 BOE/day			355,836 Mcfe/day			103,987 BOE/day

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

	Oil and natural gas sales	$	88.42		$	4.49		$	53.32
	Royalties and production taxes		(21.06	)		(0.74	)		(11.58	)
	Cash operating costs		(12.96	)		(1.04	)		(9.12	)
	Transportation		(1.69	)		(0.49	)		(2.39	)

	Netback before hedging	$	52.71		$	2.22		$	30.23

	Cash gains/(losses)		(5.23	)		(0.10	)		(2.60	)

	Netback after hedging	$	47.48		$	2.12		$	27.63

	Netback before hedging ($ millions)	$	214.4		$	71.7		$	286.1

	Netback after hedging ($ millions)	$	193.1		$	68.5		$	261.6

		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 costs		(12.31	)		(0.99	)		(8.81	)
	Transportation		(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

		Six months ended June 30, 2014
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			43,519 BOE/day			347,394 Mcfe/day			101,418 BOE/day

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

	Oil and natural gas sales	$	87.47		$	4.93		$	54.45
	Royalties and production taxes		(21.19	)		(0.79	)		(11.81	)
	Cash operating costs		(12.69	)		(1.05	)		(9.04	)
	Transportation		(1.77	)		(0.49	)		(2.45	)

	Netback before hedging	$	51.82		$	2.60		$	31.15

	Cash gains/(losses)		(4.05	)		(0.13	)		(2.17	)

	Netback after hedging	$	47.77		$	2.47		$	28.98

	Netback before hedging ($ millions)	$	408.2		$	163.6		$	571.8

	Netback after hedging ($ millions)	$	376.2		$	155.7		$	531.9

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

Our crude oil properties accounted for 88% of our corporate netback before hedging for the first half of 2015 compared to 71% for the same period in 2014. Crude oil and natural gas netbacks per BOE decreased significantly for the three and six months ended June 30, 2015 compared to the same periods in 2014 primarily due to the decline in commodity prices over the past twelve months. Realized cash hedging gains and lower royalty rates helped to offset the impact of lower prices.

ENERPLUS 2015 Q2 REPORT 15

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 for further details.

		Three months ended June 30,						Six months ended June 30,
($ millions)			2015			2014			2015			2014

Cash:
	G&A expense	$	19.9		$	18.7		$	41.3		$	39.2
	Share-based compensation expense		(1.2	)		10.7			6.0			17.5
Non-Cash:
	Share-based compensation expense		4.6			3.5			9.6			6.5
	Equity swap loss/(gain)		1.0			(4.7	)		(0.6	)		(5.9	)

Total G&A expenses		$	24.3		$	28.2		$	56.3		$	57.3

		Three months ended June 30,						Six months ended June 30,
(Per BOE)			2015			2014			2015			2014

Cash:
	G&A expense	$	2.03		$	1.97		$	2.19		$	2.14
	Share-based compensation expense		(0.13	)		1.12			0.32			0.95
Non-Cash:
	Share-based compensation expense		0.47			0.37			0.51			0.35
	Equity swap loss/(gain)		0.11			(0.49	)		(0.03	)		(0.32	)

Total G&A expenses		$	2.48		$	2.97		$	2.99		$	3.12

Cash G&A expenses during the three and six months ended June 30, 2015 were $19.9 million or $2.03/BOE and $41.3 million or $2.19/BOE, respectively, compared to $18.7 million or $1.97/BOE and $39.2 million or $2.14/BOE for the same periods in 2014. The increase in cash G&A expenses from the prior year related primarily to one-time severance payments of $2.5 million during the first half of 2015.

During the quarter, our share price decreased by 15% resulting in a cash SBC recovery of $1.2 million or $0.13/BOE compared to an expense of $10.7 million or $1.12/BOE in the same period of 2014. We recorded non-cash SBC of $4.6 million or $0.47/BOE in the second quarter compared to $3.5 million or $0.37/BOE during the same period in 2014. The increase in non-cash SBC was due to additional grants issued under the plans.

We have hedged a portion of the outstanding cash settled grants under our LTI plans. As a result of the decrease in our share price during the quarter we recorded a non-cash mark-to-market loss of $1.0 million on these hedges. As of June 30, 2015 we had 524,000 units hedged at a weighted average price of $16.51/share.

Based on our increased production guidance and continued focus on cost control, we are reducing our 2015 guidance for cash G&A expenses to $2.25/BOE from $2.40/BOE. We do not provide guidance for SBC because it is dependent on our share price and our relative performance to our peers.

Interest Expense

	Three months ended June 30,				Six months ended June 30,
($ millions)		2015		2014		2015		2014

Interest on senior notes and bank facility	$	15.9	$	16.0	$	32.7	$	30.6
Non-cash interest expense		0.2		0.5		0.5		1.1

Total interest expense	$	16.1	$	16.5	$	33.2	$	31.7

16 ENERPLUS 2015 Q2 REPORT

For the three and six month period ended June 30, 2015 we recorded total interest expense of $16.1 million and $33.2 million, respectively, compared to $16.5 million and $31.7 million for the same periods in 2014. The increase in interest expense for the six month period corresponds to an increase in higher interest rate senior notes following our September 2014 private placement of US$200 million and the impact of a weaker Canadian dollar on our U.S. dollar denominated interest expense. This was somewhat offset by senior note repayments of $88.9 million in June funded by lower rate floating bank debt, along with an overall decrease in our drawn credit facility balance following the receipt of net divestment proceeds of $187.8 million during the second quarter.

Non-cash amounts recorded in interest expense include amortization of deferred financing charges. See Note 11 for further details.

At June 30, 2015 approximately 93% of our debt was based on fixed interest rates and 7% on floating interest rates, with weighted average interest rates of 5.2% and 2.6%, respectively.

Foreign Exchange

	Three months ended June 30,						Six months ended June 30,
($ millions)		2015			2014			2015			2014

Realized loss/(gain)	$	8.4		$	16.6		$	(27.2	)	$	16.7
Unrealized loss/(gain)		(36.1	)		(23.8	)		103.7			(22.5	)

Total foreign exchange loss/(gain)	$	(27.7	)	$	(7.2	)	$	76.5		$	(5.8	)

For the three and six month period ended June 30, 2015 we recorded a net foreign exchange gain of $27.7 million and a net foreign exchange loss of $76.5 million, respectively, compared to gains of $7.2 million and $5.8 million for the same periods in 2014.

Realized losses in the second quarter included net payments of $7.1 million on our foreign exchange collars and forward contracts along with losses on 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 our US$175 million foreign exchange swaps and losses of $15.7 million on our foreign exchange collars.

Unrealized gains and losses include the translation of U.S. dollar debt and working capital and unrealized gains or losses on our foreign exchange derivatives. See Note 12 for further details.

Capital Investment

	Three months ended June 30,					Six months ended June 30,
($ millions)		2015			2014		2015			2014

Capital spending	$	148.0		$	204.4	$	315.0		$	422.2
Office capital		1.4			1.2		2.3			1.6

Sub-total	$	149.4		$	205.6	$	317.3		$	423.8

Property and land acquisitions	$	(1.0	)	$	3.2	$	(1.2	)	$	13.2
Property divestments		(187.8	)		0.5		(191.5	)		(116.7	)

Sub-total	$	(188.8	)	$	3.7	$	(192.7	)	$	(103.5	)

Total	$	(39.4	)	$	209.3	$	124.6		$	320.3

Capital spending for the three and six months ended June 30, 2015 totaled $148.0 million and $315.0 million, respectively, compared to $204.4 million and $422.2 million for the same periods in 2014. Although spending has slowed in the first half of 2015 due to continued weakness in commodity prices, we continued to invest modestly in our core areas. During the second quarter we spent $110.6 million on our Fort Berthold crude oil properties, $17.3 million on our Canadian crude properties, $12.6 million on our Marcellus assets and $7.3 million on our deep gas properties in Canada.

During the second quarter of 2015, we completed the sale of non-core assets for combined proceeds of $187.8 million, net of closing costs, which includes the previously announced sale of our Pembina waterflood assets.

ENERPLUS 2015 Q2 REPORT 17

There were no acquisitions during the second quarter of 2015, although we recorded adjustments pertaining to prior period property acquisitions. In comparison, during the second quarter of 2014 we spent $3.2 million on minor property and land acquisitions.

Despite the impact of the weakening Canadian dollar on our U.S. dollar denominated spending we continue to expect annual capital spending of $540 million.

Depletion, Depreciation, Amortization and Accretion ("DDA&A")

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

DDA&A expense	$	137.4	$	148.7	$	269.8	$	280.8
Per BOE	$	14.06	$	15.71	$	14.31	$	15.30

DDA&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, 2015 DDA&A per BOE decreased when compared the same periods of 2014 primarily due to additional reserves recognized in the 2014 year-end reserves evaluation and the effect of the previous impairment on our book value.

Impairment

Under U.S. GAAP, entities using full cost oil and gas accounting are subject to a ceiling test performed on a country by country basis using estimated after-tax future net cash flows discounted at 10% 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 reversible in future periods.

The trailing twelve month average crude oil and natural gas prices decreased significantly in the first half of the year, resulting in non-cash impairments of $497.2 million and $764.9 million (before tax) for the three and six months ended June 30, 2015, respectively. We did not record any ceiling test impairments on our oil and natural gas properties in 2014. We expect the twelve month trailing prices used in the ceiling test calculation to decline further which may lead to additional write downs of our oil and natural gas properties. See Note 5 for trailing twelve month prices and further information.

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 estimated by Enerplus based on our net ownership interest, anticipated 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 $282.5 million at June 30, 2015 compared to $288.7 million at December 31, 2014. The decrease is primarily due to the Pembina property divestment in the second quarter of 2015. Asset retirement obligation settlements for the three and six months ended June 30, 2015 totaled $2.6 million and $6.5 million, respectively, compared to $4.2 million and $8.5 million for the same periods in 2014. See Note 8 for further information.

Income Taxes

	Three months ended June 30,					Six months ended June 30,
($ millions)		2015			2014		2015			2014

Current tax expense/(recovery)	$	(0.1	)	$	3.8	$	–		$	11.5
Deferred tax expenses/(recovery)		(221.7	)		12.7		(360.1	)		37.2

Total tax expense/(recovery)	$	(221.8	)	$	16.5	$	(360.1	)	$	48.7

We recorded a total tax recovery of $221.8 million and $360.1 million for the three and six months ended June 30, 2015, respectively, compared to a $16.5 million and $48.7 million expense for the same periods in 2014. The decrease in total tax expense is primarily due to lower income in

18 ENERPLUS 2015 Q2 REPORT

2015 which includes non-cash ceiling test impairments totaling $497.2 million and $764.9 million for the three and six months ended June 30, 2015, respectively.

Given the decrease in commodity prices and U.S. forecasted net income for the year, we expect current tax of less than 1% of our U.S. funds flow in 2015. Our U.S. current tax is comprised mainly of Alternative Minimum Tax ("AMT") payable with respect to our U.S. subsidiary. We expect to recover any AMT paid in future years as an offset to regular U.S. income taxes otherwise payable. We do not expect to pay any cash taxes in Canada in 2015.

As a result, an overall current tax recovery of $0.1 million and nil has been recognized for the three and six months ended June 30, 2015, respectively, compared to a $3.8 million and $11.5 million expense for the same periods in 2014.

These estimates may vary depending on numerous factors including commodity prices, capital spending, tax regulations and acquisitions and divestment activity. See Note 13 for further information.

SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS

		Three months ended June 30, 2015									Three months ended June 30, 2014
(CDN$ millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes(1)
	Crude oil (bbls/day)		15,462			25,660			41,122			17,184			22,679			39,863
	Natural gas liquids (bbls/day)		2,136			3,009			5,145			2,476			1,160			3,636
	Natural gas (Mcf/day)		144,788			222,183			366,971			156,401			206,528			362,929

	Total average daily production (BOE/day)		41,730			65,699			107,429			45,727			58,260			103,987

Pricing(2)
	Crude oil (per bbl)	$	55.86		$	59.71		$	58.26		$	92.90		$	96.41		$	94.90
	Natural gas liquids (per bbl)		33.58			11.87			20.88			57.01			35.00			49.98
	Natural gas (per Mcf)		2.68			1.70			2.09			4.32			3.80			4.02
Capital expenditures
	Capital spending	$	24.6		$	123.4		$	148.0		$	60.4		$	144.0		$	204.4
	Acquisitions		0.8			(1.8	)		(1.0	)		–			3.2			3.2
	Divestments		(187.1	)		(0.7	)		(187.8	)		–			0.5			0.5
Netback Before Hedging
	Oil and natural gas sales	$	120.7		$	177.7		$	298.4		$	226.0		$	278.5		$	504.5
	Royalties		(11.7	)		(35.0	)		(46.7	)		(35.1	)		(54.5	)		(89.6	)
	Production taxes		(0.9	)		(13.3	)		(14.2	)		(1.9	)		(18.1	)		(20.0	)
	Cash operating expense		(49.3	)		(30.0	)		(79.3	)		(62.2	)		(24.0	)		(86.2	)
	Transportation expense		(5.8	)		(22.2	)		(28.0	)		(5.9	)		(16.7	)		(22.6	)

	Netback before hedging	$	53.0		$	77.2		$	130.2		$	120.9		$	165.2		$	286.1

Other Expenses
	Commodity derivative instruments loss/(gain)	$	19.8		$	–		$	19.8		$	44.0		$	–		$	44.0
	General and administrative expense(3)		19.2			5.1			24.3			22.6			5.6			28.2
	Current income tax expense/(recovery)		(0.4	)		0.3			(0.1	)		(0.2	)		4.0			3.8

(1): Company interest volumes.
(2): Before transportation costs, royalties and the effects of commodity derivative instruments.
(3): Includes share-based compensation.

ENERPLUS 2015 Q2 REPORT 19

		Six months ended June 30, 2015									Six months ended June 30, 2014
(CDN$ millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes(1)
	Crude oil (bbls/day)		16,213			24,030			40,243			16,882			21,935			38,817
	Natural gas liquids (bbls/day)		2,247			2,197			4,444			2,508			942			3,450
	Natural gas (Mcf/day)		140,129			216,707			356,836			154,027			200,879			354,906

	Total average daily production (BOE/day)		41,816			62,345			104,160			45,061			56,357			101,418

Pricing(2)
	Crude oil (per bbl)	$	48.37		$	53.56		$	51.35		$	89.55		$	96.09		$	93.25
	Natural gas liquids (per bbl)		31.26			11.62			21.55			63.16			43.01			57.66
	Natural gas (per Mcf)		2.90			1.95			2.32			4.70			4.28			4.46
Capital expenditures
	Capital spending	$	101.5		$	213.5		$	315.0		$	188.0		$	234.2		$	422.2
	Acquisitions		2.0			(3.2	)		(1.2	)		–			13.2			13.2
	Divestments		(188.0	)		(3.5	)		(191.5	)		(67.7	)		(49.0	)		(116.7	)
Netback Before Hedging
	Oil and natural gas sales	$	228.6		$	313.9		$	542.5		$	446.1		$	553.5		$	999.6
	Royalties		(24.0	)		(61.8	)		(85.8	)		(69.1	)		(107.8	)		(176.9	)
	Production taxes		(2.7	)		(22.3	)		(25.0	)		(3.9	)		(35.9	)		(39.8	)
	Cash operating expense		(106.4	)		(59.8	)		(166.2	)		(124.4	)		(41.7	)		(166.1	)
	Transportation expense		(12.0	)		(42.5	)		(54.5	)		(11.8	)		(33.2	)		(45.0	)

	Netback before hedging	$	83.5		$	127.5		$	211.0		$	236.9		$	334.9		$	571.8

Other Expenses
	Commodity derivative instruments loss/(gain)	$	(30.6	)	$	–		$	(30.6	)	$	76.7		$	–		$	76.7
	General and administrative expense(3)		42.7			13.6			56.3			45.9			11.4			57.3
	Current income tax expense/(recovery)		(0.4	)		0.4			–			(0.4	)		11.9			11.5

(1): Company interest volumes.
(2): Before transportation costs, royalties and the effects of commodity derivative instruments.
(3): 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

2015
Second Quarter	$	251.7	$	(312.5	)	$	(1.52	)	$	(1.52	)
First Quarter		205.0		(293.2	)		(1.42	)		(1.42	)

Total 2015	$	456.7	$	(605.7	)	$	(2.94	)	$	(2.94	)

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

2013
Fourth Quarter	$	332.4	$	29.6		$	0.15		$	0.15
Third Quarter		365.4		(3.7	)		(0.02	)		(0.02	)
Second Quarter		341.3		38.5			0.19			0.19
First Quarter		313.4		(16.4	)		(0.08	)		(0.08	)

Total 2013	$	1,352.5	$	48.0		$	0.24		$	0.24

20 ENERPLUS 2015 Q2 REPORT

Oil and natural gas sales increased during the second quarter compared to the first quarter of 2015 as production volumes increased and oil prices improved. From the first quarter of 2013, oil and natural gas sales increased steadily until the third quarter of 2014 when realized commodity prices began to decline significantly. Net income in the first half of 2015 was impacted by asset impairments related to the decrease in the trailing twelve month average commodity prices used to calculate impairments. We did not record any asset impairments in 2013 or 2014.

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, which is a senior debt to EBITDA threshold of 3.5x for a period of up to six months, after which it drops to 3.0x. At June 30, 2015 our senior debt to EBITDA ratio was 1.5x and our debt to funds flow ratio was 1.6x. The debt to funds flow ratio is often used by investors and analysts to evaluate our liquidity, however, this measure is not part of our debt covenants.

Total debt net of cash at June 30, 2015 was $1,120.7 million compared to $1,134.9 million at December 31, 2014. Total debt was comprised of $80.4 million of bank indebtedness and $1,041.3 million of senior notes less $1.0 million in cash. At June 30, 2015 we were approximately 8% drawn on our $1.0 billion senior unsecured bank facility.

During the second quarter, we repaid debt of $88.9 million on the final maturities of our US$40.0 million and $40.0 million senior notes. Following the October 1, 2015 repayment of US$10.8 million on our maturing US$54 million senior notes, we have no scheduled debt repayments until June of 2017, with remaining maturities extending to 2026.

Our working capital deficiency, excluding cash and current deferred financial and tax balances, decreased to $164.7 million at June 30, 2015 from $290.6 million at December 31, 2014. We expect to finance our working capital deficit through funds flow and our bank credit facility.

Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by funds flow, was 112% and 147% for the three and six months ended June 30, 2015, respectively, compared to 120% and 119% for the same periods in 2014. We have continued to maintain our financial flexibility through an ongoing focus on cost efficiencies and the success of our non-core asset divestment program. After adjusting for net acquisition and divestment proceeds, our adjusted payout ratio for the six months ended June 30, 2015 decreases to 75%.

As previously announced, in order to maintain our balance sheet strength we have reduced our monthly dividend by 44% to $0.05/share from $0.09/share effective with our March 2015 dividend, paid in April. Although we have revised capital spending guidance to $540 million to accelerate North Dakota oil well completions, our overall capital spending budget remains 33% lower than 2014 spending levels.

We have a $1.0 billion senior, unsecured, covenant-based bank credit facility that matures on October 31, 2017. Drawn fees range between 150 and 315 basis points over Banker's Acceptance rates, with current drawn fees of 170 basis points. The bank credit facility ranks equally with our senior, unsecured, covenant-based notes. At June 30, 2015 we were in compliance with all covenants under our bank credit facility and outstanding senior notes. 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, 2015:

Covenant Description		June 30, 2015

Bank Credit Facility:	Maximum Ratio
Senior Debt to EBITDA	3.5 x	1.5 x
Total Debt to EBITDA	4.0 x	1.5 x
Total Debt to Capitalization(1)	50% – 55%	29%
Senior Notes:	Maximum Ratio
Senior Debt to EBITDA(2)	3.0 x – 3.5x	1.5 x
Maximum debt to consolidated present value of total proven reserves	60%	37%
	Minimum Ratio
EBITDA to Interest	4.0 x	12.1 x

ENERPLUS 2015 Q2 REPORT 21

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.

"EBITDA" is calculated as net income less interest, taxes, depletion, depreciation, amortization, accretion and non-cash gains and losses. EBITDA is calculated on a trailing twelve month basis and is adjusted for material acquisitions and divestments. EBITDA for the three months and the trailing twelve months ended June 30, 2015 were $176.2 million and $780.6 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): Upon completion of a material acquisition, the Total Debt to Capitalization maximum ratio may increase to 55% for a period extending to and including the second full fiscal quarter after the completion of the acquisition.
(2): Senior Debt to EBITDA maximum ratio for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

Dividends

	Three months ended June 30,				Six months ended June 30,
($ millions, except per share amounts)		2015		2014		2015		2014

Cash dividends	$	30.9	$	50.5	$	78.3	$	92.7
Stock dividend plan		–		4.7		–		17.4

Total dividends to shareholders	$	30.9	$	55.2	$	78.3	$	110.1

Per weighted average share (Basic)	$	0.15	$	0.27	$	0.38	$	0.54

During the three and six months ended June 30, 2015 we reported total dividends of $30.9 million ($0.15/share) and $78.3 million ($0.38/share), respectively, compared to $55.2 million ($0.27/share) and $110.1 million ($0.54/share) for the same periods in 2014.

Effective with the April 2015 payment, we reduced the monthly dividend by 44% from $0.09 per share to $0.05 per share to preserve our balance sheet strength. During the second quarter, our dividends represented approximately 19% of our funds flow and at current levels we expect to spend approximately $124 million annually on dividends, a decrease from $221.1 million in 2014. Additionally, in September 2014 we elected to suspend our stock dividend plan, thereby eliminating any dilution resulting from issuing shares as part of our dividend plan.

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,
		2015		2014

Share capital ($ millions)	$	3,126.6	$	3,102.2
Common shares outstanding (thousands)		206,224		204,768
Weighted average shares outstanding – basic (thousands)		206,028		203,671
Weighted average shares outstanding – diluted (thousands)		206,028		207,563

During the second quarter of 2015 a total of 45,000 shares (2014 – 929,000) and $0.6 million of additional equity (2014 – $17.8 million) was issued pursuant to the stock option plan and the currently inactive stock dividend plan. For the six months ended June 30, 2015 a total of 492,000 shares (2014 – 2,010,000) and $6.3 million of additional equity (2014 – $36.7 million) was issued pursuant to the stock option plan, the treasury settled Restricted Share Unit plan and the currently inactive stock dividend plan. For further details see Note 14.

At June 30, 2015 we had 206,224,000 shares outstanding (2014 – 204,768,000) and at August 6, 2015 we had 206,224,000 shares outstanding.

22 ENERPLUS 2015 Q2 REPORT

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, 2015 we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.

2015 GUIDANCE

We have increased our production guidance and have reduced our operating cost and G&A expense guidance by a total of $0.65/BOE. All other guidance has been maintained and is summarized below. This guidance does not include any unannounced acquisitions or divestments.

Summary of 2015 Expectations		Target

Average annual production		100,000 – 104,000 BOE/day (from 97,000 – 103,000 BOE/day)
Capital spending		$540 million
Production mix (volumes)		44,000 – 46,000 bbls/day of crude oil and natural gas liquids
Average royalty and production tax rate (% of gross sales, before transportation)		21%
Operating expenses		$9.25/BOE (from $9.75/BOE)
Transportation costs		$3.00/BOE
Cash G&A expenses		$2.25/BOE (from $2.40/BOE)
U.S. cash taxes (% of U.S. funds flow)		< 1%

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, 2015, 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, 2015 and ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ENERPLUS 2015 Q2 REPORT 23

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 2015 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 balance sheet and funds flow; our commodity and foreign exchange risk management programs in 2015 and in the future; the results from our drilling program and the timing of related production; oil and natural gas prices, including twelve month trailing prices used in calculation of a ceiling test impairment under U.S. GAAP; 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 2015 and its impact on our production level; potential future asset impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and expectations regarding Canadian cash 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; our future acquisitions and dispositions, including timing thereof and expected use of proceeds therefrom; 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 further curtailment of production and/or reduced realized prices; current commodity price 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 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; the availability of third party services; and the extent of our liabilities. In addition, our 2015 guidance contained in this MD&A is based on the following July 22, 2015 forward prices: a WTI price of US$51.99/bbl, a NYMEX price of US$2.89/Mcf, and AECO price of $2.75/GJ and a CDN/USD exchange rate of 1.27.

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 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 in, including 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; our risk management programs, including commodity hedging, being less effective in protecting our balance sheet and funds flow than anticipated; 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; changes in estimates of our reserves and resource volumes; limited, unfavorable or a lack of access to capital markets; our inability to comply with covenants under our bank credit facility and senior notes; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; failure to complete any of the anticipated acquisitions or dispositions; 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 our Annual MD&A and in our other public filings).

24 ENERPLUS 2015 Q2 REPORT

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Exhibit 99.1

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Exhibit 99.2

STATEMENTS

Condensed Consolidated Balance Sheets

(CDN$ thousands) unaudited		Note		June 30, 2015			December 31, 2014

Assets
Current Assets
	Cash		$	1,002		$	2,036
	Accounts receivable	3		161,284			199,745
	Deferred financial assets	15		83,617			215,706
	Other current assets			14,868			8,241

				260,771			425,728

Property, plant and equipment:
	Oil and natural gas properties (full cost method)	4		1,852,801			2,632,474
	Other capital assets, net	4		20,265			20,591

	Property, plant and equipment			1,873,066			2,653,065

Goodwill				637,429			624,390
Deferred income tax asset				685,988			348,117
Deferred financial assets		15		6,446			30,997

Total Assets			$	3,463,700		$	4,082,297

Liabilities
Current liabilities
	Accounts payable	6	$	317,043		$	351,006
	Dividends payable			10,311			18,516
	Current portion of long-term debt	7		13,472			98,933
	Deferred income tax liability			16,254			50,805
	Deferred financial credits	15		17,819			10,826

				374,899			530,086

Deferred financial credits		15		–			2,396
Long-term debt		7		1,108,210			1,037,997
Asset retirement obligation		8		282,474			288,692

				1,390,684			1,329,085

Total Liabilities				1,765,583			1,859,171

Shareholders' Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2015 – 206 million shares December 31, 2014 – 206 million shares		14		3,126,568			3,120,002
Paid-in capital		14		53,106			46,906
Accumulated deficit				(1,723,304	)		(1,039,260	)
Accumulated other comprehensive income/(loss)				241,747			95,478

				1,698,117			2,223,126

Total Liabilities & Equity			$	3,463,700		$	4,082,297

Contingencies		16

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2015 Q2 REPORT 25

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

			Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) unaudited		Note		2015			2014			2015			2014

Revenues
Oil and natural gas sales, net of royalties		9	$	251,730		$	414,925		$	456,690		$	822,665
Commodity derivative instruments gain/(loss)		15		(19,751	)		(44,069	)		30,647			(76,666	)

				231,979			370,856			487,337			745,999

Expenses
Production taxes				14,220			19,974			25,033			39,846
Operating				76,744			86,018			164,471			165,875
Transportation				28,018			22,630			54,501			44,963
General and administrative		10		24,262			28,180			56,342			57,303
Depletion, depreciation, amortization and accretion				137,403			148,656			269,753			280,836
Asset impairment		5		497,247			–			764,858			–
Interest		11		16,121			16,522			33,154			31,701
Foreign exchange (gain)/loss		12		(27,656	)		(7,225	)		76,546			(5,756	)
Other expense/(income)				(85	)		(360	)		8,527			2,552

				766,274			314,395			1,453,185			617,320

Income/(loss) before taxes				(534,295	)		56,461			(965,848	)		128,679
Current income tax expense/(recovery)		13		(102	)		3,797			(39	)		11,475
Deferred income tax expense/(recovery)		13		(221,649	)		12,707			(360,059	)		37,210

Net Income/(Loss)			$	(312,544	)	$	39,957		$	(605,750	)	$	79,994

Other Comprehensive Income/(Loss)
Changes due to marketable securities (net of tax)
	Unrealized gain/(loss)			–			–			–			(145	)
	Realized (gain)/loss reclassified to net income			–			–			–			2,503
Change in cumulative translation adjustment				(30,490	)		(43,414	)		146,269			2,230

Other Comprehensive Income/(Loss)				(30,490	)		(43,414	)		146,269			4,588

Total Comprehensive Income/(Loss)			$	(343,034	)	$	(3,457	)	$	(459,481	)	$	84,582

Net income/(loss) per share
Basic		14	$	(1.52	)	$	0.20		$	(2.94	)	$	0.39
Diluted		14	$	(1.52	)	$	0.19		$	(2.94	)	$	0.39

See accompanying notes to the Condensed Consolidated Financial Statements

26 ENERPLUS 2015 Q2 REPORT

Condensed Consolidated Statements of Changes
in Shareholders' Equity

Six months ended June 30 (CDN$ thousands) unaudited			2015			2014

Share Capital
Balance, beginning of year		$	3,120,002		$	3,061,839
Stock Option Plan – cash			3,205			19,193
Share-based compensation – settled			3,094			–
Stock Option Plan – exercised			267			3,683
Stock Dividend Plan			–			17,487

Balance, end of period		$	3,126,568		$	3,102,202

Paid-in Capital
Balance, beginning of year		$	46,906		$	38,398
Share-based compensation – settled			(3,094	)		–
Stock Option Plan – exercised			(267	)		(3,683	)
Share-based compensation – non-cash			9,561			6,494

Balance, end of period		$	53,106		$	41,209

Accumulated Deficit
Balance, beginning of year		$	(1,039,260	)	$	(1,117,238	)
Net income/(loss)			(605,750	)		79,994
Dividends			(78,294	)		(110,149	)

Balance, end of period		$	(1,723,304	)	$	(1,147,393	)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of year		$	95,478		$	(50,697	)
Changes due to marketable securities (net of tax)
	Unrealized gain/(loss)		–			(145	)
	Realized (gain)/loss reclassified to net income		–			2,503
Change in cumulative translation adjustment			146,269			2,230

Balance, end of period		$	241,747		$	(46,109	)

Total Shareholders' Equity		$	1,698,117		$	1,949,909

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2015 Q2 REPORT 27

Condensed Consolidated Statements of Cash Flows

			Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) unaudited		Note		2015			2014			2015			2014

Operating Activities
Net income/(loss)			$	(312,544	)	$	39,957		$	(605,750	)	$	79,994
Non-cash items add/(deduct):
	Depletion, depreciation, amortization and accretion			137,403			148,656			269,753			280,836
	Asset impairment	5		497,247			–			764,858			–
	Changes in fair value of derivative instruments	15		73,738			130			161,237			6,939
	Deferred income tax expense/(recovery)	13		(221,649	)		12,707			(360,059	)		37,210
	Foreign exchange (gain)/loss on debt and working capital	12		(18,590	)		(9,052	)		69,424			1,935
	Share-based compensation	14		4,591			3,542			9,561			6,494
	Amortization of debt issue costs			240			247			480			493
	Asset divestments (gain)/loss			–			–			–			2,798
Derivative settlement on senior notes				–			17,024			(39,904	)		17,024
Asset retirement obligation expenditures		8		(2,569	)		(4,240	)		(6,459	)		(8,532	)
Changes in non-cash operating working capital		17		(22,771	)		19,535			3,051			(56,275	)

Cash flow from operating activities				135,096			228,506			266,192			368,916

Financing Activities
Proceeds from the issuance of shares		14		634			13,055			3,205			19,193
Cash dividends		14		(30,935	)		(50,508	)		(78,294	)		(92,662	)
Change in bank credit facility				(45,386	)		107,280			434			76,710
Repayment of senior notes				(88,897	)		(37,898	)		(88,897	)		(37,898	)
Derivative settlement on senior notes				–			(17,024	)		39,904			(17,024	)
Changes in non-cash financing working capital				(15	)		103			(8,222	)		204

Cash flow from financing activities				(164,599	)		15,008			(131,870	)		(51,477	)

Investing Activities
Capital and office expenditures				(149,439	)		(205,623	)		(317,327	)		(423,816	)
Property and land acquisitions				1,011			(3,231	)		1,247			(13,200	)
Property dispositions				187,801			(525	)		191,513			116,700
Sale of marketable securities				–			–			–			13,300
Changes in non-cash investing working capital				(12,148	)		(35,482	)		(11,217	)		(10,805	)

Cash flow from investing activities				27,225			(244,861	)		(135,784	)		(317,821	)

Effect of exchange rate changes on cash				677			(2,392	)		428			(610	)

Change in cash				(1,601	)		(3,739	)		(1,034	)		(992	)
Cash, beginning of period				2,603			5,737			2,036			2,990

Cash, end of period			$	1,002		$	1,998		$	1,002		$	1,998

See accompanying notes to the Condensed Consolidated Financial Statements

28 ENERPLUS 2015 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 6, 2015.

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, 2015 and the 2014 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, 2014. 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, 2014.

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, 2015			December 31, 2014

Accrued receivables	$	130,839		$	136,949
Accounts receivable – trade		26,389			41,618
Current income tax receivable		6,798			23,900
Allowance for doubtful accounts		(2,742	)		(2,722	)

Total accounts receivable	$	161,284		$	199,745

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

As at June 30, 2015 ($ thousands)		Cost		Accumulated Depletion, Depreciation, and Impairment			Net Book Value

Oil and natural gas properties	$	12,945,978	$	(11,093,177	)	$	1,852,801
Other capital assets		101,274		(81,009	)		20,265

Total PP&E	$	13,047,252	$	(11,174,186	)	$	1,873,066

As at December 31, 2014 ($ thousands)		Cost		Accumulated Depletion, Depreciation, and Impairment			Net Book Value

Oil and natural gas properties	$	12,478,953	$	(9,846,479	)	$	2,632,474
Other capital assets		97,893		(77,302	)		20,591

Total PP&E	$	12,576,846	$	(9,923,781	)	$	2,653,065

ENERPLUS 2015 Q2 REPORT 29

5) ASSET IMPAIRMENT

		Three months ended June 30,				Six months ended June 30,
($ thousands)			2015		2014		2015		2014

Oil and natural gas properties:
	Canada cost centre	$	28,100	$	–	$	28,100	$	–
	U.S. cost centre		469,147		–		736,758		–

Total impairment expense		$	497,247	$	–	$	764,858	$	–

The impairments for the three and six months ended June 30, 2015 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, 2014 through June 30, 2015:

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 2015	$	71.75	$	1.16	$	75.83	$	3.42	$	3.33
Q1 2015		82.73		1.14		84.61		3.88		3.86
Q4 2014		94.99		1.09		94.84		4.30		4.60
Q3 2014		99.08		1.08		95.97		4.23		4.42
Q2 2014		100.27		1.06		98.28		4.08		4.05

6) ACCOUNTS PAYABLE

($ thousands)		June 30, 2015		December 31, 2014

Accrued payables	$	230,815	$	239,773
Accounts payable – trade		86,228		111,233

Total accounts payable	$	317,043	$	351,006

7) DEBT

($ thousands)			June 30, 2015		December 31, 2014

Current:
	Senior notes	$	13,472	$	98,933

			13,472		98,933

Long-term:
	Bank credit facility	$	80,351	$	79,917
	Senior notes		1,027,859		958,080

			1,108,210		1,037,997

Total debt		$	1,121,682	$	1,136,930

30 ENERPLUS 2015 Q2 REPORT

8) ASSET RETIREMENT OBLIGATION

Enerplus has estimated the present value of its asset retirement obligation to be $282.5 million at June 30, 2015 compared to $288.7 million at December 31, 2014 based on a total undiscounted liability of $698.2 million and $730.9 million, respectively. The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.95% (December 31, 2014 – 5.92%).

($ thousands)		Six months ended June 30, 2015			Year ended December 31, 2014

Balance, beginning of year	$	288,692		$	291,761
Change in estimates		4,779			4,378
Property acquisitions and development activity		586			1,778
Dispositions		(13,411	)		(4,313	)
Settlements		(6,459	)		(19,409	)
Accretion expense		8,287			14,497

Balance, end of period	$	282,474		$	288,692

9) OIL AND NATURAL GAS SALES

	Three months ended June 30						Six months ended June 30
($ thousands)		2015			2014			2015			2014

Oil and natural gas sales	$	298,433		$	504,551		$	542,510		$	999,575
Royalties(1)		(46,703	)		(89,626	)		(85,820	)		(176,910	)

Oil and natural gas sales, net of royalties	$	251,730		$	414,925		$	456,690		$	822,665

(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)			2015		2014		2015		2014

	General and administrative expense	$	19,872	$	18,672	$	41,307	$	39,201
	Share-based compensation expense		4,390		9,508		15,035		18,102

General and administrative expense		$	24,262	$	28,180	$	56,342	$	57,303

11) INTEREST EXPENSE

		Three months ended June 30				Six months ended June 30
($ thousands)			2015		2014		2015		2014

Realized:
	Interest on bank debt and senior notes	$	15,881	$	15,962	$	32,674	$	30,628
Unrealized:
	Cross currency interest rate swap (gain)/loss		–		313		–		580
	Amortization of debt issue costs		240		247		480		493

Interest expense		$	16,121	$	16,522	$	33,154	$	31,701

ENERPLUS 2015 Q2 REPORT 31

12) FOREIGN EXCHANGE

		Three months ended June 30						Six months ended June 30
($ thousands)			2015			2014			2015			2014

Realized:
	Foreign exchange (gain)/loss	$	8,402		$	16,626		$	(27,172	)	$	16,676
Unrealized:
	Translation of U.S. dollar debt and working capital (gain)/loss		(18,590	)		(9,052	)		69,424			1,935
	Cross currency interest rate swap (gain)/loss		–			(14,885	)		–			(16,130	)
	Foreign exchange derivatives (gain)/loss		(17,468	)		86			34,294			(8,237	)

Foreign exchange (gain)/loss		$	(27,656	)	$	(7,225	)	$	76,546		$	(5,756	)

13) INCOME TAXES

		Three months ended June 30						Six months ended June 30
($ thousands)			2015			2014			2015			2014

Current tax expense/(recovery)
	Canada	$	(400	)	$	(190	)	$	(400	)	$	(374	)
	United States		298			3,987			361			11,849

Current tax expense/(recovery)			(102	)		3,797			(39	)		11,475

Deferred tax expense/(recovery)
	Canada	$	(27,676	)	$	(7,005	)	$	(36,939	)	$	(5,318	)
	United States		(193,973	)		19,712			(323,120	)		42,528

Deferred tax expense/(recovery)			(221,649	)		12,707			(360,059	)		37,210

Income tax expense/(recovery)		$	(221,751	)	$	16,504		$	(360,098	)	$	48,685

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

14) SHAREHOLDERS' EQUITY

a) Share Capital

		Six months ended June 30			Year ended December 31

		2015			2014

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

Balance, beginning of year		205,732	$	3,120,002	202,758	$	3,061,839
Issued for cash:
	Stock Option Plan	234		3,205	1,944		31,350
Non-cash:
	Share-based compensation – settled	258		3,094	–		–
	Stock Option Plan – exercised	–		267	–		4,978
	Stock Dividend Plan(1)	–		–	1,030		21,835

Balance, end of period		206,224	$	3,126,568	205,732	$	3,120,002

(1): Effective with the October 2014 dividend, Enerplus suspended the Stock Dividend Plan.

32 ENERPLUS 2015 Q2 REPORT

b) Dividends

	Three months ended June 30				Six months ended June 30
($ thousands)		2015		2014		2015		2014

Cash dividends	$	30,935	$	50,508	$	78,294	$	92,662
Stock dividends(1)		–		4,706		–		17,487

Dividends to shareholders	$	30,935	$	55,214	$	78,294	$	110,149

(1): Effective with the October 2014 dividend, Enerplus suspended the Stock Dividend Plan.

c) 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)			2015			2014			2015			2014

Cash:
	Long-term incentive plans expense	$	(1,233	)	$	10,648		$	6,041		$	17,512
Non-cash:
	Long-term incentive plans expense		4,453			2,856			9,035			3,691
	Stock option plan expense		138			686			526			2,803
	Equity swap (gain)/loss		1,032			(4,682	)		(567	)		(5,904	)

Share-based compensation expense		$	4,390		$	9,508		$	15,035		$	18,102

(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 will continue to be settled in cash.

The following table summarizes the PSU, RSU and Director Share Unit ("DSU") activity for the six months ended June 30, 2015:

For the six months ended June 30, 2015	Cash-settled LTI plans						Equity-settled LTI Plans
(thousands of units)	PSU		RSU		DSU		PSU		RSU		Total

Balance, beginning of year	406		398		122		510		775		2,211
Granted	–		–		77		948		1,389		2,414
Vested	(120	)	(214	)	(19	)	–		(258	)	(611	)
Forfeited	(10	)	(27	)	–		(13	)	(109	)	(159	)

Balance, end of period	276		157		180		1,445		1,797		3,855

Cash-settled LTI Plans

For the three and six months ended June 30, 2015 the Company recorded a cash share-based compensation recovery of $1.2 million and an expense of $6.0 million, respectively (June 30, 2014 – $10.6 million expense and $17.5 million expense). For the three and six months ended June 30, 2015 the Company made cash payments of nil and $5.6 million, respectively, related to its cash-settled plans (June 30, 2014 – $0.3 million and $11.8 million).

ENERPLUS 2015 Q2 REPORT 33

The following table summarizes the cumulative share-based compensation expense recognized to-date, which has been recorded to Accounts Payable on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to cash share-based compensation expense over the remaining vesting terms.

At June 30, 2015 ($ thousands, except for years)		PSU(1)		RSU		DSU		Total

Cumulative recognized share-based compensation expense	$	10,103	$	2,326	$	2,329	$	14,758
Unrecognized share-based compensation expense		1,215		302		–		1,517

Intrinsic value	$	11,318	$	2,628	$	2,329	$	16,275

Weighted-average remaining contractual term (years)		0.5		0.4		–

(1): Includes estimated performance multipliers.

Equity-settled LTI Plans

For the three and six months ended June 30, 2015 the Company recorded non-cash share-based compensation expense of $4.5 million and $9.0 million, respectively (2014 – $2.9 million and $3.7 million).

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, 2015 ($ thousands, except for years)		PSU(1)		RSU		Total

Cumulative recognized share-based compensation expense	$	5,099	$	13,284	$	18,383
Unrecognized share-based compensation expense		10,997		15,534		26,531

Fair value	$	16,096	$	28,818	$	44,914

Weighted-average remaining contractual term (years)		2.1		1.6

(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, 2015. The following table summarizes the stock option plan activity for the period ended June 30, 2015:

Period ended June 30, 2015		Number of Options (thousands)			Weighted Average Exercise Price

Options outstanding, beginning of year		10,368		$	18.65
	Granted	–			–
	Exercised	(234	)		13.71
	Forfeited	(653	)		20.01

Options outstanding, end of period		9,481		$	18.68

Options exercisable, end of period		7,489		$	19.96

At June 30, 2015 7,489,000 options were exercisable at a weighted average reduced exercise price of $19.96 with a weighted average remaining contractual term of 3.7 years, giving an aggregate intrinsic value of nil (2014 – $36.7 million). The intrinsic value of options exercised for the three and six months ended June 30, 2015 was $0.1 million and $0.2 million, respectively (June 30, 2014 – $5.2 million and $8.1 million).

At June 30, 2015 the total share-based compensation expense related to non-vested options not yet recognized was $0.4 million. The expense is expected to be recognized in net income over a weighted-average period of 0.7 years.

34 ENERPLUS 2015 Q2 REPORT

d) Paid-in Capital

The following table summarizes the paid-in capital activity for the six months ended June 30, 2015 and the year ended December 31, 2014:

($ thousands)		Six months ended June 30, 2015			Year Ended December 31, 2014

Balance, beginning of year	$	46,906		$	38,398
Share-based compensation – settled		(3,094	)		–
Stock Option Plan – exercised		(267	)		(4,978	)
Share-based compensation – non-cash		9,561			13,486

Balance, end of period	$	53,106		$	46,906

e) Basic and Diluted Earnings 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)			2015			2014		2015			2014

Net income/(loss)		$	(312,544	)	$	39,957	$	(605,750	)	$	79,994
Weighted average shares outstanding – Basic			206,208			204,158		206,028			203,671
Dilutive impact of share-based compensation(1)			–			4,364		–			3,892

Weighted average shares outstanding – Diluted			206,208			208,522		206,028			207,563

Net income/(loss) per share
	Basic	$	(1.52	)	$	0.20	$	(2.94	)	$	0.39
	Diluted(1)		(1.52	)		0.19		(2.94	)		0.39

(1): For the three and six months ended June 30, 2015 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, 2015 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, 2015 senior notes had a carrying value of $1,041.3 million and a fair value of $1,121.0 million (December 31, 2014 – $1,057.0 million and $1,150.0 million, respectively).

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

b) Derivative Financial Instruments

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

ENERPLUS 2015 Q2 REPORT 35

The following table summarizes the change in fair value for the three and six months ended June 30, 2015 and 2014.

		Three months ended June 30,						Six months ended June 30,
Gain/(Loss) ($ thousands)			2015			2014			2015			2014		Income Statement Presentation

Cross Currency Interest Rate Swap
	Interest	$	–		$	(313	)	$	–		$	(580	)	Interest expense
	Foreign Exchange		–			14,885			–			16,130		Foreign exchange
Foreign Exchange Derivatives			17,468			(86	)		(34,294	)		8,237		Foreign exchange
Electricity Swaps			2,642			228			1,715			182		Operating expense
Equity Swaps			(1,032	)		4,682			567			5,904		General and administrative expense
Commodity Derivative Instruments:
	Oil		(71,085	)		(24,810	)		(107,044	)		(34,203	)	Commodity derivative
	Gas		(21,731	)		5,284			(22,181	)		(2,609	)	instruments

Total		$	(73,738	)	$	(130	)	$	(161,237	)	$	(6,939	)

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

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2015			2014			2015			2014

Change in fair value gain/(loss)	$	(92,816	)	$	(19,526	)	$	(129,225	)	$	(36,812	)
Net realized cash gain/(loss)		73,065			(24,543	)		159,872			(39,854	)

Commodity derivative instruments gain/(loss)	$	(19,751	)	$	(44,069	)	$	30,647		$	(76,666	)

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

		June 30, 2015						December 31, 2014
		Assets				Liabilities		Assets				Liabilities
($ thousands)			Current		Long-term		Current		Current		Long-term		Current		Long-term

Foreign Exchange Derivatives		$	2,519	$	–	$	14,966	$	1,616	$	28,665	$	8,434	$	–
Electricity Swaps			347		–		–		–		–		1,368		–
Equity Swaps			–		–		2,853		–		–		1,024		2,396
Commodity Derivative Instruments:
	Oil		53,697		6,446		–		167,187		–		–		–
	Gas		27,054		–		–		46,903		2,332		–		–

Total		$	83,617	$	6,446	$	17,819	$	215,706	$	30,997	$	10,826	$	2,396

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.

36 ENERPLUS 2015 Q2 REPORT

The following tables summarize the Corporation's price risk management positions at July 22, 2015:

Crude Oil Instruments:

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

Jul 1, 2015 – Sep 30, 2015
WTI Swap	8,000	93.86
WTI Purchased Call	4,000	93.00
WTI Sold Put	4,000	62.23
WCS Differential Swap	4,000	(16.61	)
MSW Differential Swap	1,000	(3.50	)
Oct 1, 2015 – Dec 31, 2015
WTI Swap	12,500	82.10
WTI Purchased Put	2,000	63.00
WTI Sold Call	2,000	70.00
WTI Purchased Call	4,000	93.00
WTI Sold Put	6,000	57.49
WCS Differential Swap	4,000	(16.61	)
MSW Differential Swap	1,000	(3.50	)
Jan 1, 2016 – Jun 30, 2016
WTI Swap	3,000	64.28
WTI Purchased Put	8,000	64.38
WTI Sold Call	8,000	79.38
WTI Sold Put	8,000	50.13
WCS Differential Swap	2,000	(14.50	)
Jul 1, 2016 – Dec 31, 2016
WTI Purchased Put	11,000	64.35
WTI Sold Call	11,000	80.09
WTI Sold Put	11,000	49.34
WCS Differential Swap	2,000	(14.50	)

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

Natural Gas Instruments:

Instrument Type	MMcf/day	US$/Mcf

Jul 1, 2015 – Sep 30, 2015
NYMEX Swap	155.0	3.73
NYMEX Purchased Call	5.0	4.29
NYMEX Sold Put	5.0	3.25
NYMEX Sold Call	5.0	5.00
Oct 1, 2015 – Oct 31, 2015
NYMEX Swap	115.0	3.85
NYMEX Purchased Call	5.0	4.29
NYMEX Sold Put	5.0	3.25
NYMEX Sold Call	5.0	5.00
Nov 1, 2015 – Dec 31, 2015
NYMEX Swap	95.0	4.04
NYMEX Purchased Call	5.0	4.29
NYMEX Sold Put	5.0	3.25
NYMEX Sold Call	5.0	5.00
Jan 1, 2016 – Dec 31, 2016
NYMEX Purchased Put	25.0	3.00
NYMEX Sold Put	25.0	2.50
NYMEX Sold Call	25.0	3.75

ENERPLUS 2015 Q2 REPORT 37

Electricity Instruments:

Instrument Type	MWh	CDN$/MWh

Jul 1, 2015 – Dec 31, 2015
AESO Power Swap(1)	16.0	48.30
Jan 1, 2016 – Dec 31, 2016
AESO Power Swap(1)	12.0	47.00

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

Physical Contracts:

Instrument Type	MMcf/day	US$/Mcf

Jul 1, 2015 – Oct 31, 2015	60.0	(0.65	)
AECO-NYMEX Basis
Nov 1, 2015 – Oct 31, 2016	60.0	(0.67	)
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. Enerplus manages currency risk through the derivative instruments detailed below.

Foreign Exchange Derivatives:

During 2015 Enerplus entered into foreign exchange forward rate swaps for July through December 2015 to buy US$6 million per month at an average US$/CDN$ exchange rate of 1.20 to partially mitigate losses on the foreign exchange collars entered into in 2014.

During 2014 Enerplus entered into foreign exchange collars to protect a portion of its foreign exchange exposure on U.S. dollar denominated oil and gas sales with upside participation in the event the Canadian dollar weakened. As of June 30, 2015 we have US$24 million per month hedged for the remainder of 2015 at an average USD/CDN floor of 1.1088, a ceiling of 1.1845 and a conditional ceiling of 1.1263.

During 2011 Enerplus entered into foreign exchange swaps on US$175.0 million of notional debt at approximately par. During 2015 Enerplus unwound these swaps and recognized a gain of $39.9 million and an offsetting non-cash loss of $27.6 million which have been included in foreign exchange gain/loss on the Consolidated Statements of Income/(Loss).

During 2007 Enerplus entered in foreign exchange swaps on US$54.0 million of notional debt at an average US$/CDN$ exchange rate of 1.02. The remaining $10.8 million notional amount under the swap matures in October 2015 in conjunction with the final principal repayment on the US$54.0 million senior notes.

Interest Rate Risk:

At June 30, 2015 approximately 93% of Enerplus' debt was based on fixed interest rates and 7% was based on floating interest rates. At June 30, 2015 Enerplus did not have any interest rate derivatives outstanding.

38 ENERPLUS 2015 Q2 REPORT

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 2015 and 2017 and has effectively fixed the figure settlement cost on 524,000 shares at weighted average price of $16.51 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, 2015 approximately 63% of Enerplus' marketing receivables were with companies considered investment grade.

At June 30, 2015 approximately $4.7 million or 3% 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, 2015 was $2.7 million (December 31, 2014 – $2.7 million).

(iii) Liquidity Risk & Capital Management

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash) and 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, 2015 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.

ENERPLUS 2015 Q2 REPORT 39

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2015			2014			2015			2014

Accounts receivable	$	(5,371	)	$	12,292		$	18,696		$	(19,877	)
Other current assets		(10,079	)		(379	)		(14,877	)		544
Accounts payable		(7,321	)		7,622			(768	)		(36,942	)

	$	(22,771	)	$	19,535		$	3,051		$	(56,275	)

b) Other

	Three months ended June 30,				Six months ended June 30,
($ thousands)		2015		2014		2015			2014

Income taxes paid/(received)	$	148	$	18,521	$	(19,197	)	$	18,387
Interest paid	$	25,936	$	26,305	$	32,418		$	28,688

40 ENERPLUS 2015 Q2 REPORT

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Exhibit 99.2

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Exhibit 99.3

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE

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

1.

Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Enerplus Corporation (the "issuer") for the interim period ended June 30, 2015.

2.

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

3.

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

4.

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

5.

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

(a)

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

(i): material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii): information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)

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

5.1

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

5.2

ICFR — material weakness relating to design: N/A

5.3

Limitation on scope of design: N/A

6.

Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer's ICFR that occurred during the period beginning on April 1, 2015 and ended on June 30, 2015 that has materially affected, or is reasonably likely to materially affect, the issuer's ICFR.


Date: August 7, 2015
(signed by) Ian C. Dundas President and Chief Executive Officer Enerplus Corporation

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Exhibit 99.3

FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE

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Exhibit 99.4

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE

I, ROBERT J. WATERS, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:

1.

Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Enerplus Corporation (the "issuer") for the interim period ended June 30, 2015.

2.

3.

4.

5.

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

(a)

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

(i): material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii): information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)

5.1

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

5.2