Report of Foreign Issuer (6-k)

Share Name	Share Symbol	Market	Type
Enerplus Corporation	NYSE:ERF	NYSE	Common Stock

	Price Change	% Change	Share Price	High Price	Low Price	Open Price	Shares Traded	Last Trade
	0.00	0.00%	20.09				0	01:00:00

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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 NOVEMBER, 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 Third Quarter ended September 30, 2015

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September 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: November 6, 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 November 5, 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 nine months ended September 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 expenses and transportation costs.

ENERPLUS 2015 Q3 REPORT 7

		Three months ended September 30,						Nine months ended September 30,
Calculation of Netback ($ millions)			2015			2014			2015			2014

Oil and natural gas sales		$	275.7		$	456.2		$	818.2		$	1,455.8
Less:
	Royalties		(47.4	)		(77.9	)		(133.2	)		(254.8	)
	Production taxes		(13.9	)		(21.3	)		(38.9	)		(61.1	)
	Cash operating expenses(1)		(88.6	)		(88.8	)		(254.8	)		(254.9	)
	Transportation costs		(30.9	)		(27.9	)		(85.4	)		(72.9	)

Netback before hedging		$	94.9		$	240.3		$	305.9		$	812.1
	Cash gains/(losses) on derivative instruments		54.1			(2.5	)		214.0			(42.4	)

Netback after hedging		$	149.0		$	237.8		$	519.9		$	769.7

(1): Operating costs adjusted to exclude non-cash losses on fixed price electricity swaps of $1.8 million and $0.1 million in the three and nine months ended September 30, 2015 (non-cash gains of nil and $0.2 million in the three and nine months ended September 30, 2014).

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

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

Cash flow from operating activities	$	122.6		$	199.1	$	388.8		$	568.0
Asset retirement obligation expenditures		4.2			3.3		10.6			11.8
Changes in non-cash operating working capital		(6.0	)		10.4		(9.0	)		66.7

Funds Flow	$	120.8		$	212.8	$	390.4		$	646.5

"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 September 30,				Nine months ended September 30,
Calculation of Adjusted Payout Ratio ($ millions)		2015		2014		2015		2014

Cash dividends(1)	$	30.9	$	51.1	$	109.2	$	143.8
Capital and office expenditures		89.9		209.2		407.2		633.0

Sub-total	$	120.8	$	260.3	$	516.4	$	776.8
Funds flow	$	120.8	$	212.8	$	390.4	$	646.5

Adjusted payout ratio (%)		100%		122%		132%		120%

(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.

8 ENERPLUS 2015 Q3 REPORT

OVERVIEW

We continued to benefit from the momentum of our strong operational performance in the third quarter, while maintaining our balance sheet strength. We have delivered production growth and met or exceeded all of our guidance targets year-to-date. As a result, we are increasing our 2015 annual average production guidance by 4,000 BOE/day from the mid-point, reducing our capital spending guidance by $30 million and reducing our operating cost and general administrative ("G&A") expense guidance by $0.30/BOE, overall.

Production for the third quarter was 110,794 BOE/day, an increase of 3% compared to the second quarter and ahead of our annual average production guidance range of 100,000-104,000 BOE/day. Production increased by 3,365 BOE/day primarily due to additional well on-streams in our core oil play in Fort Berthold, North Dakota, where crude oil production increased by 4,795 BOE/day or 22% compared to the second quarter of 2015. With continued production outperformance in Fort Berthold, we are increasing our 2015 annual production guidance to 106,000 BOE/day and expect approximately 46,000 bbls/day of crude oil and natural gas liquids.

Our capital spending for the third quarter was $88.9 million, down from $148.0 million in the second quarter with most of our spending focused on our core crude oil plays. As a result of continued cost improvements, deferral of spending into 2016 and strong operational performance, we are decreasing our annual capital spending guidance from $540 million to $510 million.

Third quarter funds flow decreased to $120.8 million from $160.4 million in the second quarter as realized oil prices declined during the period. Our commodity price hedges continued to provide funds flow protection with cash gains of $54.1 million recorded during the quarter.

The continued decline in the twelve month average commodity price used to calculate impairments in accordance with U.S. GAAP resulted in a non-cash asset impairment charge of $321.2 million (before tax) in the quarter and $1,086.0 million (before tax) for the nine months ended September 30, 2015. Accordingly, we reported a net loss for the quarter of $292.7 million compared to a net loss of $312.5 million in the second quarter of 2015.

Operating costs for the quarter were in line with expectations at $90.4 million. As expected, we saw an increase in operating costs with seasonal turnaround activity, however on a per BOE basis, operating costs came in below guidance of $9.25/BOE at $8.87/BOE due to higher production. Cash G&A costs were in line with guidance of $2.25/BOE, at $22.8 million or $2.24/BOE, despite one-time severance charges that were incurred in the quarter. As a result of our continued focus on cost reductions and increased production guidance range, we are decreasing our operating cost guidance to $9.00/BOE and our G&A expense guidance to $2.20/BOE.

Subsequent to the quarter end, we completed a one year extension of our senior, unsecured, covenant-based bank credit facility, which now matures on October 31, 2018. As part of the extension, we chose to decrease our bank credit facility from $1.0 billion to $800 million after confirming with our syndicate banks that we could have maintained the facility at its current level. This decision balanced the need for sufficient liquidity to execute our business plan with the associated costs of maintaining a largely undrawn bank facility.

Despite the decline in commodity prices during the last year, we have remained in a strong financial position. At September 30, 2015, we had a debt to funds flow ratio of 2.0x and senior debt to EBITDA ratio of 1.8x. After a US$10.8 million senior note repayment in the fourth quarter of 2015 we have no term debt repayments until June of 2017. Subsequent to the quarter, we have taken additional steps to preserve our financial strength. We are reducing our monthly dividend to $0.03 per share from $0.05 per share effective with our December dividend payment. In addition, we have entered into an agreement to sell a portion of our non-operated North Dakota acreage for proceeds of $80 million, bringing our year to date net divestment proceeds to $283.4 million. This divestment represents less than 2% of our overall North Dakota acreage with forecast 2016 production from the existing wells of 1,000 BOE/day. We expect the sale to close during the fourth quarter. As a result of these initiatives, coupled with our continuing operational excellence, we expect to deliver a sustainable and balanced strategy for 2016.

2016 OUTLOOK

Our capital spending guidance for 2016 is $350 million, a decrease of approximately 30% from 2015 guidance of $510 million. With a focus on efficiencies and targeted spending across our core areas, we expect this spending level will allow us to essentially sustain production levels at 100,000-105,000 BOE/day, including 44,000-47,000 bbls/day of crude oil and natural gas liquids.

We expect 2016 operating expenses to average $9.20/BOE, a slight increase from $9.00/BOE in 2015, primarily due to the impact of a weak Canadian dollar on our U.S. dollar denominated operating costs and the marginal decline in production in 2016.

We are providing cash G&A guidance of $1.90/BOE, down $0.30/BOE from 2015 guidance as a result of continued cost savings initiatives and a reduction in staff.

ENERPLUS 2015 Q3 REPORT 9

We expect transportation costs of $3.00/BOE and an average royalty and production tax rate of 22%.

RESULTS OF OPERATIONS

Production

Production for the third quarter totaled 110,794 BOE/day, exceeding our guidance range of 100,000-104,000 BOE/day and increasing 3% compared to 107,429 BOE/day in the second quarter of 2015. This increase was driven primarily by oil production in Fort Berthold, which increased 22% or 4,795 BOE/day compared to the prior quarter. Natural gas production levels were consistent with the second quarter, with outperformance in the Marcellus offsetting a decrease in Canadian deep gas production due to scheduled turnarounds at major facilities. As a result, crude oil and natural gas liquids production in the third quarter increased to 45% of our total average daily production, up from 43% in the second quarter of 2015.

Production in the third quarter of 2015 increased 6% from 104,035 BOE/day in the same period of 2014. Crude oil production increased 11% largely due to our ongoing development program in Fort Berthold, which saw a 38% increase in crude oil production compared to the prior year. Over the same period, natural gas production increased by 2%, with growth in our Marcellus production more than offsetting the impact of our disposition of non-core gas weighted properties during the second half of 2014.

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

	Three months ended September 30,			Nine months ended September 30,
Average Daily Production Volumes	2015	2014	% Change	2015	2014	% Change

Crude oil (bbls/day)	44,888	40,332	11%	41,809	39,328	6%
Natural gas liquids (bbls/day)	5,061	3,869	31%	4,652	3,591	30%
Natural gas (Mcf/day)	365,071	359,007	2%	359,611	356,288	1%

Total daily sales (BOE/day)	110,794	104,035	6%	106,396	102,300	4%

As a result of continued outperformance we are revising our average annual production guidance upward to 106,000 BOE/day from 100,000-104,000 BOE/day, with approximately 46,000 bbls/day of crude oil and natural gas liquids. This increase in guidance includes lower projected fourth quarter oil production due to divestments and reduced on-stream activity in Fort Berthold.

In 2016, we expect annual average production of 100,000-105,000 BOE/day, including 44,000-47,000 bbls/day of crude oil and natural gas liquids. We expect this will be achieved despite significantly lower capital spending in 2016 and the fourth quarter sale of a portion of our North Dakota acreage.

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 the nine month period ended September 30, 2015 and 2014 and quarterly average prices from the third quarter of 2014 to the third quarter of 2015:

10 ENERPLUS 2015 Q3 REPORT

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

Benchmarks
	WTI crude oil (US$/bbl)	$	51.00		$	99.61		$	46.43		$	57.94		$	48.64		$	73.15		$	97.17
	AECO natural gas – monthly index (CDN$/Mcf)		2.80			4.55			2.80			2.67			2.95			4.01			4.22
	AECO natural gas – daily index (CDN$/Mcf)		2.77			4.81			2.90			2.64			2.75			3.60			4.02
	NYMEX natural gas – last day (US$/Mcf)		2.80			4.55			2.77			2.64			2.98			4.00			4.06
	US/CDN exchange rate		1.26			1.09			1.31			1.23			1.24			1.14			1.09
Enerplus Selling Price(1)
	Crude oil (CDN$/bbl)	$	50.21		$	92.55		$	48.22		$	58.26		$	44.04		$	69.17		$	88.28
	Natural gas liquids (CDN$/bbl)		18.60			54.79			13.51			20.88			22.48			42.34			46.76
	Natural gas (CDN$/Mcf)		2.24			4.18			2.08			2.09			2.58			3.25			3.36

Average differentials
	MSW Edmonton – WTI (US$/bbl)	$	(4.43	)	$	(7.44	)	$	(3.42	)	$	(3.06	)	$	(6.80	)	$	(6.36	)	$	(7.93	)
	WCS Hardisty – WTI (US$/bbl)		(13.20	)		(21.12	)		(13.27	)		(11.59	)		(14.73	)		(14.24	)		(20.18	)
	Brent Futures (ICE) – WTI (US$/bbl)		5.66			7.40			4.77			5.63			6.58			3.85			6.25
	AECO monthly – NYMEX (US$/Mcf)		(0.57	)		(0.40	)		(0.63	)		(0.47	)		(0.60	)		(0.47	)		(0.18	)
Enerplus realized differentials(1)
	Canada crude oil – WTI (US$/bbl)	$	(13.33	)	$	(19.08	)	$	(11.82	)	$	(12.50	)	$	(15.22	)	$	(12.17	)	$	(20.51	)
	Canada natural gas – NYMEX (US$/Mcf)		(0.45	)		(0.26	)		(0.43	)		(0.46	)		(0.46	)		(0.62	)		(0.29	)
	Bakken crude oil – WTI (US$/bbl)		(9.84	)		(11.89	)		(8.52	)		(9.30	)		(11.65	)		(12.15	)		(12.81	)
	Marcellus natural gas – NYMEX (US$/Mcf)		(1.46	)		(1.36	)		(1.64	)		(1.39	)		(1.32	)		(1.62	)		(1.70	)

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

Crude Oil and Natural Gas Liquids

WTI crude oil prices fell by 20% versus the previous quarter to average US$46.43/bbl during the third quarter. Crude oil supply continued to exceed global demand. The agreement reached early in the quarter that allowed for increased Iranian crude oil exports and other sanctions relief in exchange for increased inspections and monitoring of the Iranian nuclear program exacerbated market concerns over the supply-demand imbalance, pushing oil prices sharply lower. The sell-off in crude was also driven by concerns over China's economy and the considerable losses realized in their stock market over the summer. This pushed WTI prices down to a low of US$38.24/bbl before stabilizing at approximately US$45.00/bbl by the end of the quarter.

The weakness in WTI prices and differentials was offset by a significantly weaker US/CDN dollar exchange rate. Our realized crude oil price declined by approximately 17% to average $48.22/bbl during the third quarter. The heavy crude oil differential tightened to US$7.44/bbl below WTI in July due to the impact of production outages in Northern Alberta and then widened to US$18.97/bbl as a result of a major Midwest U.S. refinery fire in late August. Light sweet crude oil price differentials experienced similar volatility due to unplanned refinery outages resulting in Canadian light sweet differentials being slightly weaker than in the second quarter averaging US$3.42/bbl below WTI.

We saw improvement in our U.S. Bakken crude oil differential during the third quarter as U.S. oil production has started to decline. Our realized Bakken differential was US$8.52/bbl below WTI compared to US$9.30/bbl below WTI in the second quarter. Subsequent to the third quarter we have seen differentials improve further. For 2016, we expect a Bakken differential of US$8.00/bbl below WTI.

The decline in crude oil prices plus the continued build in natural gas liquids inventories in the U.S. pushed benchmark prices for liquids lower once again during the third quarter. Propane stocks increased by over 9 million barrels, sending U.S. benchmark propane prices significantly lower. Propane prices in Canada continued to trade negative during the third quarter as a result of the oversupply of propane in the Canadian market. Prices for condensate in both the U.S. and Canada were also lower this quarter due to the 20% decline in WTI prices. As a result, we realized an average price for our natural gas liquids of $13.51/bbl which is a 35% decrease from the second quarter.

ENERPLUS 2015 Q3 REPORT 11

Natural Gas

Natural gas prices at AECO (monthly) and on the NYMEX were slightly stronger during the third quarter, both averaging 5% higher than the previous quarter. Natural gas in storage in the U.S. at September 30, 2015 was 3.6 Tcf, which is near the highest level we have seen at this time of the year relative to the past five years, and remains on track to reach 4.0 Tcf. Mild temperatures and ongoing concerns over the impact a strong El Nino weather pattern may have on natural gas demand this winter has driven current NYMEX prices lower. Our realized natural gas price in the third quarter of 2015 averaged $2.08/Mcf, which was largely unchanged from the previous quarter with weaker Marcellus differentials offsetting the strength in AECO and NYMEX prices.

Strong production levels and significant maintenance activities on the two major pipelines running through Northeast Pennsylvania contributed to continued weakness in regional Marcellus pricing during the quarter. Transco Leidy Pipeline and Tennessee Gas Pipeline Marcellus spot prices averaged US$1.71/Mcf below NYMEX. As we continue to have a significant portion of our Marcellus production linked to markets outside of the production region, our realized Marcellus gas price averaged US$1.64/Mcf below NYMEX. This was 18% lower than the second quarter. Basis differentials have improved subsequent to the quarter-end in the region, with spot prices in the Marcellus trading approximately US$1.00/Mcf to US$1.50/Mcf below NYMEX, due to weaker NYMEX prices and the recent tie-in of new regional export pipeline capacity. For 2016, we expect a Marcellus differential of US$1.25/Mcf below NYMEX.

Foreign Exchange

The Canadian dollar weakened during the third quarter, averaging US/CDN 1.31. In July, we saw the Canadian dollar fall to a six year low 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 Canadian dollar continued to depreciate in August and September as a result of decreasing commodity prices, exiting the quarter at a US/CDN exchange rate of 1.34; a level not experienced since 2004. The majority of our crude oil and natural gas sales are based on U.S. dollar denominated indices and 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.

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. Hedging activity was minimal during the third quarter due to the current commodity price environment. For the fourth quarter of 2015, we have an average of 14,500 bbls/day of crude oil (approximately 45% of our expected crude oil production, net of royalties) hedged at an average floor price of US$79.47/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 have not added materially to our gas hedging program with prices remaining weak during the quarter. For the fourth quarter of 2015 we are swapped on an average of 101,739 Mcf/day (approximately 36% of our forecasted natural gas production, net of royalties) at an average price of US$3.97/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.

12 ENERPLUS 2015 Q3 REPORT

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

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

Downside Protection – Swaps
Sold Swaps	$	82.10	$	64.28		–	$	3.85	$	4.04		–
%		39%		9%		–		41%		34%		–
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		–		–	$	3.25	$	3.25		–
%		12%		–		–		2%		2%		–
Purchased Calls	$	93.00		–		–	$	4.29	$	4.29		–
%		12%		–		–		2%		2%		–
Sold Calls		–		–		–	$	5.00	$	5.00		–
%		–		–		–		2%		2%		–

(1): Based on weighted average price (before premiums), assumed average annual production of 106,000 BOE/day for 2015 and 100,000 – 105,000 BOE/day for 2016, less royalties and production taxes of 21.0% and 22.0% in aggregate, respectively.

We have also entered into WCS and MSW differential swap positions to manage our exposure to Canadian crude oil differentials. At October 22, 2015, we have 4,000 bbls/day of WCS swapped at US$(16.61)/bbl and 1,333 bbls/day of MSW swapped at US$(3.28)/bbl for the fourth quarter of 2015. For 2016, we have 3,000 bbls/day of WCS swapped at US$(14.03)/bbl and 1,000 bbls/day of MSW swapped at US$(3.50)/bbl.

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

	MMcf/day		US$/Mcf

Oct 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 US/CDN 1.20 to partially mitigate our losses on these collars. As of October 22, 2015, we effectively have US$18 million per month hedged for 2015 at an average US/CDN floor of

ENERPLUS 2015 Q3 REPORT 13

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. We do not have any foreign exchange contracts in place for 2016.

ACCOUNTING FOR PRICE RISK MANAGEMENT

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

Cash gains/(losses):
	Crude oil	$	36.6		$	(4.2	)	$	163.8		$	(36.2	)
	Natural gas		17.5			1.7			50.2			(6.2	)

Total cash gains/(losses)		$	54.1		$	(2.5	)	$	214.0		$	(42.4	)
Non-cash gains/(losses):
	Change in fair value – crude oil	$	35.1		$	82.9		$	(71.9	)	$	48.7
	Change in fair value – natural gas		(8.2	)		10.9			(30.4	)		8.3

Total non-cash gains/(losses)		$	26.9		$	93.8		$	(102.3	)	$	57.0

Total gains		$	81.0		$	91.3		$	111.7		$	14.6

	Three months ended September 30,					Nine months ended September 30,
(Per BOE)		2015		2014			2015			2014

Total cash gains/(losses)	$	5.31	$	(0.26	)	$	7.36		$	(1.52	)
Total non-cash gains/(losses)		2.64		9.80			(3.52	)		2.04

Total gains	$	7.95	$	9.54		$	3.84		$	0.52

During the third quarter of 2015 we realized cash gains of $36.6 million on our crude oil contracts and $17.5 million on our natural gas contracts. In comparison, during the third quarter of 2014 we realized cash losses of $4.2 million on our crude oil contracts and cash gains of $1.7 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 third quarter of 2015 the fair value of our crude oil and natural gas contracts represented net gain positions of $95.3 million and $18.8 million, respectively. For the three and nine months ended September 30, 2015 the change in the fair value of our crude oil contracts represented gains of $35.1 million and losses of $71.9 million, respectively, and our natural gas contracts represented losses of $8.2 million and $30.4 million, respectively.

During the three and nine months ended September 30, 2015 we recorded total cash losses on our foreign exchange collars of $10.9 million and $26.6 million, respectively. At September 30, 2015 the fair value of foreign exchange derivatives was a net loss of $9.2 million. See Note 15 for further information.

Revenues

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2015			2014			2015			2014

Oil and natural gas	$	275.7		$	456.2		$	818.2		$	1,455.8
Royalties		(47.4	)		(77.9	)		(133.2	)		(254.8	)

Oil and natural gas sales, net of royalties	$	228.3		$	378.3		$	685.0		$	1,201.0

14 ENERPLUS 2015 Q3 REPORT

Oil and natural gas revenues for the three and nine months ended September 30, 2015 were $228.3 million and $685.0 million, respectively, compared to $378.3 million and $1,201.0 million for the same periods in 2014. The decrease in revenue for both the three and nine month periods was driven primarily by the weak commodity price environment offset somewhat by an increase in production volumes.

Royalties and Production Taxes

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Royalties	$	47.4	$	77.9	$	133.2	$	254.8
Per BOE	$	4.65	$	8.14	$	4.59	$	9.12
Production taxes	$	13.9	$	21.3	$	38.9	$	61.1
Per BOE	$	1.36	$	2.22	$	1.34	$	2.19

Royalties and production taxes	$	61.3	$	99.2	$	172.1	$	315.9
Per BOE	$	6.01	$	10.36	$	5.93	$	11.31
Royalties and production taxes (% of oil and natural gas sales, before transportation)		22%		22%		21%		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 nine months ended September 30, 2015 royalties and production taxes decreased to $61.3 million and $172.1 million, respectively, from $99.2 million and $315.9 million for the same periods in 2014, primarily due to lower realized prices. Royalties and production taxes as a percentage of oil and natural gas sales before transportation averaged 22% and 21% for the three and nine months ended September 30, 2015, respectively, compared to 22% for the same periods in 2014.

We continue to expect an average royalty and production tax rate of 21% in 2015 with a slight increase to 22% in 2016 as a result of increased U.S. production with a higher effective royalty and production tax rate.

Operating Expenses

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Operating expenses	$	90.4	$	88.9	$	254.9	$	254.7
Per BOE	$	8.87	$	9.28	$	8.77	$	9.12

Effective January 1, 2015 we 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 with no impact on our netback, funds flow or net income. All comparative periods have been presented to conform to the current period presentation.

For the three and nine months ended September 30, 2015 operating expenses were $90.4 million or $8.87/BOE and $254.9 million or $8.77/BOE, respectively, compared to $88.9 million or $9.28/BOE and $254.7 million or $9.12/BOE for the same periods in 2014. As expected, our third quarter 2015 operating costs increased over the previous quarter as a result of planned maintenance activity, the impact of a weakening Canadian dollar on our U.S. dollar denominated operating expenses and non-cash losses of $1.8 million on our electricity hedges. Overall, operating costs per BOE decreased during the three and nine months ended September 30, 2015 compared to the prior year due to higher production volumes and realized cost saving initiatives, offset in part by the impact of a weaker Canadian dollar.

Based on our cost savings to date and our increased production guidance, we are reducing our 2015 guidance for operating expenses to $9.00/BOE from $9.25/BOE. Although year to date operating costs are below our revised guidance, we are expecting oil production to decrease in the fourth quarter as a result of reduced on-stream activity in Fort Berthold and our fourth quarter divestment.

ENERPLUS 2015 Q3 REPORT 15

For 2016, we expect operating costs to average $9.20/BOE, a slight increase from 2015 operating costs per BOE. This is primarily due to the full year impact of a US/CDN exchange rate of 1.33 and a marginal decline in production in 2016.

Transportation Costs

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

Transportation costs	$	30.9	$	27.9	$	85.4	$	72.9
Per BOE	$	3.03	$	2.92	$	2.94	$	2.61

As discussed previously in operating expenses, we have reclassified Marcellus gathering costs 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 nine months ended September 30, 2015 transportation costs were $30.9 million or $3.03/BOE and $85.4 million or $2.94/BOE, respectively, compared to $27.9 million or $2.92/BOE and $72.9 million or $2.61/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 annual transportation cost guidance of $3.00/BOE for 2015 and 2016.

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 September 30, 2015
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			52,764 BOE/day			348,180 Mcfe/day			110,794 BOE/day

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

	Oil and natural gas sales	$	43.34		$	2.04		$	27.04
	Royalties and production taxes		(11.02	)		(0.24	)		(6.01	)
	Cash operating expenses		(11.48	)		(1.03	)		(8.69	)
	Transportation costs		(1.74	)		(0.70	)		(3.03	)

	Netback before hedging	$	19.10		$	0.07		$	9.31

	Cash gains/(losses)		7.53			0.55			5.31

	Netback after hedging	$	26.63		$	0.62		$	14.62

	Netback before hedging ($ millions)	$	92.7		$	2.2		$	94.9

	Netback after hedging ($ millions)	$	129.2		$	19.8		$	149.0

16 ENERPLUS 2015 Q3 REPORT

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

Average Daily Production			45,263 BOE/day			352,632 Mcfe/day			104,035 BOE/day

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

	Oil and natural gas sales	$	77.98		$	4.06		$	47.67
	Royalties and production taxes		(20.73	)		(0.40	)		(10.36	)
	Cash operating expenses		(9.05	)		(1.58	)		(9.29	)
	Transportation costs		(1.91	)		(0.62	)		(2.92	)

	Netback before hedging	$	46.29		$	1.46		$	25.10

	Cash gains/(losses)		(1.01	)		0.05			(0.26	)

	Netback after hedging	$	45.28		$	1.51		$	24.84

	Netback before hedging ($ millions)	$	192.8		$	47.5		$	240.3

	Netback after hedging ($ millions)	$	188.6		$	49.2		$	237.8

		Nine months ended September 30, 2015
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			48,930 BOE/day			344,796 Mcfe/day			106,396 BOE/day

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

	Oil and natural gas sales	$	45.62		$	2.22		$	28.17
	Royalties and production taxes		(10.99	)		(0.27	)		(5.93	)
	Cash operating expenses		(11.99	)		(1.00	)		(8.77	)
	Transportation costs		(1.79	)		(0.65	)		(2.94	)

	Netback before hedging	$	20.85		$	0.30		$	10.53

	Cash gains/(losses)		12.26			0.53			7.36

	Netback after hedging	$	33.11		$	0.83		$	17.89

	Netback before hedging ($ millions)	$	278.4		$	27.5		$	305.9

	Netback after hedging ($ millions)	$	442.2		$	77.7		$	519.9

		Nine months ended September 30, 2014
Netbacks by Property Type			Crude Oil			Natural Gas			Total

Average Daily Production			44,317 BOE/day			347,898 Mcfe/day			102,300 BOE/day

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

	Oil and natural gas sales	$	84.58		$	4.55		$	52.13
	Royalties and production taxes		(21.08	)		(0.64	)		(11.31	)
	Cash operating expenses		(11.38	)		(1.23	)		(9.14	)
	Transportation costs		(1.80	)		(0.54	)		(2.61	)

	Netback before hedging	$	50.32		$	2.14		$	29.07

	Cash gains/(losses)		(2.99	)		(0.07	)		(1.52	)

	Netback after hedging	$	47.33		$	2.07		$	27.55

	Netback before hedging ($ millions)	$	608.9		$	203.2		$	812.1

	Netback after hedging ($ millions)	$	572.7		$	197.0		$	769.7

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

Our crude oil properties accounted for 91% of our corporate netback before hedging for the nine months ended September 30, 2015 compared to 75% for the same period in 2014. Crude oil and natural gas netbacks per BOE decreased significantly for the three and nine months ended September 30, 2015 compared to the same periods in 2014 primarily due to the decline in commodity prices. Realized cash hedging gains along with lower royalty rates and lower operating expenses helped to offset the impact of lower prices.

ENERPLUS 2015 Q3 REPORT 17

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 September 30,						Nine months ended September 30,
($ millions)			2015			2014			2015		2014

Cash:
	G&A expense	$	22.8		$	18.9		$	64.1	$	58.1
	Share-based compensation		(3.6	)		(5.2	)		2.5		12.3
Non-Cash:
	Share-based compensation		7.8			3.4			17.4		9.9
	Equity swap loss/(gain)		2.0			5.8			1.4		(0.1	)

Total G&A expenses		$	29.0		$	22.9		$	85.4	$	80.2

		Three months ended September 30,						Nine months ended September 30,
(Per BOE)			2015			2014			2015		2014

Cash:
	G&A expense	$	2.24		$	1.97		$	2.21	$	2.08
	Share-based compensation		(0.35	)		(0.54	)		0.08		0.44
Non-Cash:
	Share-based compensation		0.77			0.36			0.60		0.35
	Equity swap loss/(gain)		0.19			0.61			0.05		–

Total G&A expenses		$	2.85		$	2.40		$	2.94	$	2.87

Cash G&A expenses during the three and nine months ended September 30, 2015 were $22.8 million ($2.24/BOE) and $64.1 million ($2.21/BOE), respectively, compared to $18.9 million ($1.97/BOE) and $58.1 million ($2.08/BOE) for the same periods in 2014. The increase in cash G&A expenses compared to 2014 were a result of one-time severance payments of $8.5 million or $0.29/BOE year to date offset by cost savings.

During the quarter, our share price decreased by 41% resulting in a cash SBC recovery of $3.6 million or $0.35/BOE compared to a recovery of $5.2 million or $0.54/BOE in the same period of 2014. We recorded non-cash SBC of $7.8 million or $0.77/BOE in the third quarter compared to $3.4 million or $0.36/BOE during the same period in 2014. The increase in non-cash SBC was a result of additional grants issued under the LTI plans, along with one-time severance charges.

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 $2.0 million on these hedges. As of September 30, 2015 we had 470,000 units hedged at a weighted average price of $16.89 per share.

As a result of cost savings realized to date, we are reducing our cash G&A guidance to $2.20/BOE from $2.25/BOE. We do not provide guidance for SBC because it is dependent on our share price and our relative performance to our peers.

For 2016, we are providing cash G&A guidance of $1.90/BOE, down $0.30/BOE or 14% from 2015 guidance as a result of staff reductions and ongoing cost savings efforts.

Interest Expense

	Three months ended September 30,				Nine months ended September 30,
($ millions)		2015		2014		2015		2014

Interest on senior notes and bank facility	$	16.3	$	14.9	$	48.9	$	45.5
Non-cash interest expense		0.2		0.3		0.8		1.4

Total interest expense	$	16.5	$	15.2	$	49.7	$	46.9

18 ENERPLUS 2015 Q3 REPORT

For the three and nine months ended September 30, 2015 we recorded total interest expense of $16.5 million and $49.7 million, respectively, compared to $15.2 million and $46.9 million for the same periods in 2014. The increase in interest expense for the three and nine month period was primarily due to the impact of a weakening Canadian dollar on our U.S. dollar denominated interest expense, along with an overall increase in senior notes with higher interest rates compared to our bank credit facility following our September 2014 private placement of US$200 million.

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

At September 30, 2015 approximately 91% of our debt was based on fixed interest rates and 9% on floating interest rates, with weighted average interest rates of 5.2% and 2.4%, respectively.

Foreign Exchange

	Three months ended September 30,					Nine months ended September 30,
($ millions)		2015		2014			2015			2014

Realized loss/(gain)	$	8.8	$	(2.6	)	$	(18.4	)	$	14.0
Unrealized loss/(gain)		60.8		33.1			164.6			10.7

Total foreign exchange loss/(gain)	$	69.6	$	30.5		$	146.2		$	24.7

US/CDN exchange rate		1.31		1.09			1.26			1.09

For the three and nine months ended September 30, 2015 we recorded net foreign exchange losses of $69.6 million and $146.2 million, respectively, compared to losses of $30.5 million and $24.7 million for the same periods in 2014.

Realized losses of $8.8 million in the third quarter included net payments of $10.9 million on our foreign exchange collars and forward contracts offset by gains on day-to-day transactions recorded in foreign currencies. During the nine months ended September 30, 2015 we recorded realized gains of $18.4 million primarily due to a $39.9 million gain on the unwind of our US$175 million foreign exchange swaps during the first quarter which were offset by cumulative losses of $26.6 million on our foreign exchange collars caused by a continued weakening of the Canadian dollar.

Unrealized losses include the translation of U.S. dollar debt and working capital as well as changes in fair value of our foreign exchange derivatives. See Note 12 for further details.

Capital Investment

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2015			2014			2015			2014

Capital spending	$	88.9		$	207.8		$	403.9		$	630.0
Office capital		1.0			1.4			3.3			3.0

Sub-total		89.9			209.2			407.2			633.0

Property and land acquisitions	$	2.0		$	4.0		$	0.8		$	17.2
Property divestments		(11.9	)		(68.9	)		(203.4	)		(185.6	)

Sub-total		(9.9	)		(64.9	)		(202.6	)		(168.4	)

Total	$	80.0		$	144.3		$	204.6		$	464.6

Capital spending for the three and nine months ended September 30, 2015 totaled $88.9 million and $403.9 million, respectively, compared to $207.8 million and $630.0 million for the same periods in 2014. Although we slowed spending due to weak commodity prices, we continued to invest modestly in our core areas. During the third quarter we spent $58.1 million on our Fort Berthold crude oil properties, $23.9 million on our Canadian crude oil properties, $3.3 million on our Marcellus assets and $2.8 million on our deep gas properties in Canada.

We disposed of non-core Canadian oil properties in Southeast Saskatchewan during the third quarter for proceeds of $11.9 million. In the third quarter of 2014 we divested of $68.9 million of non-core natural gas properties in the deep basin area with production of approximately 1,900 BOE/day.

ENERPLUS 2015 Q3 REPORT 19

Subsequent to the quarter end, we entered into an agreement to sell a portion of our non-operated North Dakota properties for proceeds of $80 million. This divestment represents less than 2% of our total North Dakota acreage with forecast 2016 production from the existing wells of 1,000 BOE/day. We expect it to close during the fourth quarter. Including this sale, we have recorded year to date net divestment proceeds of $283.4 million.

Due to continued cost improvements, strong operational performance and the deferral of spending into 2016, we have reduced our 2015 guidance for capital spending to $510 million from $540 million.

For 2016, we expect capital spending to be $350 million with approximately 90% directed to oil and liquids properties. As a result of continued cost savings and efficiencies, we expect this lower capital spending budget will allow us to essentially sustain our 2015 production levels through targeted spending across our core areas, while preserving our balance sheet.

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

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2015		2014		2015		2014

DDA&A expense	$	131.5	$	159.7	$	401.3	$	440.5
Per BOE	$	12.90	$	16.68	$	13.81	$	15.77

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 nine months ended September 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 year to date 2015 impairments 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 have decreased significantly over the first three quarters of 2015 and resulted in non-cash impairments for the three and nine months ended September 30, 2015 of $321.2 million and $1,086.0 million (before tax), 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 impairments of our oil and natural gas properties. See Note 5 for trailing twelve month prices and additional 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 $286.0 million at September 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 nine months ended September 30, 2015 totaled $4.2 million and $10.6 million, respectively, compared to $3.3 million and $11.8 million for the same periods in 2014. See Note 8 for further information.

20 ENERPLUS 2015 Q3 REPORT

Income Taxes

	Three months ended September 30,					Nine months ended September 30,
($ millions)		2015			2014		2015			2014

Current tax expense/(recovery)	$	(16.2	)	$	–	$	(16.2	)	$	11.4
Deferred tax expense/(recovery)		(84.9	)		36.9		(445.0	)		74.1

Total tax expense/(recovery)	$	(101.1	)	$	36.9	$	(461.2	)	$	85.5

We recorded a total tax recovery of $101.1 million and $461.2 million for the three and nine months ended September 30, 2015, respectively, compared to an expense of $36.9 million and $85.5 million for the same periods in 2014. The decrease in total tax expense is due primarily to lower income in 2015 which includes non-cash ceiling test impairments for Canada and the U.S. This results in an overall net deferred income tax asset of $793.6 million as at September 30, 2015. We expect to have sufficient future taxable income in both the U.S. and Canada to realize the benefit of this asset.

The current tax recovery of $16.2 million for the nine months ended September 30, 2015 increased in comparison to the $11.4 million expense that was recorded for the same period in 2014. This recovery primarily relates to an expected Alternative Tax Net Operating Loss in the U.S., which we plan to carry-back to recover Alternative Minimum Tax that was previously paid in 2013 and 2014.

These estimates may vary depending on numerous factors including commodity prices, capital spending, tax regulations and acquisition and divestment activity.

SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS

		Three months ended September 30, 2015									Three months ended September 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)		14,478			30,410			44,888			16,837			23,495			40,332
	Natural gas liquids (bbls/day)		1,731			3,330			5,061			2,578			1,291			3,869
	Natural gas (Mcf/day)		131,644			233,427			365,071			154,855			204,152			359,007

	Total average daily production (BOE/day)		38,150			72,644			110,794			45,224			58,811			104,035

Pricing(2)
	Crude oil (per bbl)	$	45.31		$	49.60		$	48.22		$	83.50		$	91.71		$	88.28
	Natural gas liquids (per bbl)		25.31			7.37			13.51			46.45			47.39			46.76
	Natural gas (per Mcf)		3.07			1.53			2.08			4.10			2.79			3.36
Capital expenditures
	Capital spending	$	29.4		$	59.5		$	88.9		$	55.2		$	152.6		$	207.8
	Acquisitions		0.9			1.1			2.0			2.0			2.0			4.0
	Divestments		(11.8	)		(0.1	)		(11.9	)		(68.9	)		–			(68.9	)
Netback(4) Before Hedging
	Oil and natural gas sales	$	101.8		$	173.9		$	275.7		$	199.3		$	256.9		$	456.2
	Royalties		(11.8	)		(35.6	)		(47.4	)		(27.1	)		(50.8	)		(77.9	)
	Production taxes		(1.3	)		(12.6	)		(13.9	)		(2.5	)		(18.8	)		(21.3	)
	Cash operating expenses		(55.9	)		(32.7	)		(88.6	)		(64.7	)		(24.1	)		(88.8	)
	Transportation costs		(5.4	)		(25.5	)		(30.9	)		(6.2	)		(21.7	)		(27.9	)

	Netback before hedging	$	27.4		$	67.5		$	94.9		$	98.8		$	141.5		$	240.3

Other Expenses
	Commodity derivative instruments loss/(gain)	$	(81.0	)	$	–		$	(81.0	)	$	(91.3	)	$	–		$	(91.3	)
	General and administrative expense(3)		23.9			5.1			29.0			19.8			3.1			22.9
	Current tax expense/(recovery)		–			(16.2	)		(16.2	)		(0.1	)		0.1			–

(1): Company interest volumes.
(2): Before transportation costs, royalties and the effects of commodity derivative instruments.
(3): Includes share-based compensation.
(4): See "Non-GAAP Measures" section in this MD&A.

ENERPLUS 2015 Q3 REPORT 21

		Nine months ended September 30, 2015									Nine months ended September 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)		15,629			26,180			41,809			16,867			22,461			39,328
	Natural gas liquids (bbls/day)		2,073			2,579			4,652			2,531			1,060			3,591
	Natural gas (Mcf/day)		137,270			222,341			359,611			154,306			201,982			356,288

	Total average daily production (BOE/day)		40,580			65,816			106,396			45,116			57,184			102,300

Pricing(2)
	Crude oil (per bbl)	$	47.41		$	51.89		$	50.21		$	88.12		$	95.88		$	92.55
	Natural gas liquids (per bbl)		29.59			9.77			18.60			57.54			48.24			54.79
	Natural gas (per Mcf)		2.95			1.80			2.24			4.69			3.78			4.18
Capital expenditures
	Capital spending	$	131.0		$	272.9		$	403.9		$	243.2		$	386.8		$	630.0
	Acquisitions		2.9			(2.1	)		0.8			2.0			15.2			17.2
	Divestments		(199.9	)		(3.5	)		(203.4	)		(136.6	)		(49.0	)		(185.6	)
Netback(4) Before Hedging
	Oil and natural gas sales	$	330.4		$	487.8		$	818.2		$	645.3		$	810.5		$	1,455.8
	Royalties		(35.8	)		(97.4	)		(133.2	)		(96.2	)		(158.6	)		(254.8	)
	Production taxes		(4.0	)		(34.9	)		(38.9	)		(6.4	)		(54.7	)		(61.1	)
	Cash operating expenses		(162.3	)		(92.5	)		(254.8	)		(189.1	)		(65.8	)		(254.9	)
	Transportation costs		(17.4	)		(68.0	)		(85.4	)		(17.9	)		(55.0	)		(72.9	)

	Netback before hedging	$	110.9		$	195.0		$	305.9		$	335.7		$	476.4		$	812.1

Other Expenses
	Commodity derivative instruments loss/(gain)	$	(111.7	)	$	–		$	(111.7	)	$	(14.6	)	$	–		$	(14.6	)
	General and administrative expense(3)		66.6			18.8			85.4			65.7			14.5			80.2
	Current tax expense/(recovery)		(0.4	)		(15.8	)		(16.2	)		(0.5	)		11.9			11.4

(1): Company interest volumes.
(2): Before transportation costs, royalties and the effects of commodity derivative instruments.
(3): Includes share-based compensation.
(4): See "Non-GAAP Measures" section in this MD&A.

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
Third Quarter	$	228.3	$	(292.7	)	$	(1.42	)	$	(1.42	)
Second Quarter		251.7		(312.5	)		(1.52	)		(1.52	)
First Quarter		205.0		(293.2	)		(1.42	)		(1.42	)

Total 2015	$	685.0	$	(898.4	)	$	(4.36	)	$	(4.36	)

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

22 ENERPLUS 2015 Q3 REPORT

Oil and natural gas sales decreased during the third quarter compared to the second quarter of 2015 as commodity prices weakened, offset by increasing production. 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 losses incurred during 2015 have been due to asset impairments related to the decrease in the trailing twelve month average commodity prices. 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 September 30, 2015, our senior debt to EBITDA ratio was 1.8x and our debt to funds flow ratio was 2.0x. Although it is not included in our debt covenants, the debt to funds flow ratio is often used by investors and analysts to evaluate our liquidity.

Our working capital deficiency, excluding cash and current deferred financial and tax balances, decreased to $135.2 million at September 30, 2015 from $260.5 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 100% and 132% for the three and nine months ended September 30, 2015, respectively, compared to 122% and 120% for the same periods in 2014. We have continued to maintain our financial flexibility through an ongoing focus on cost efficiencies, the success of our non-core asset divestment program, disciplined capital spending and a reduction in dividends. After adjusting for net acquisition and divestment proceeds, our adjusted payout ratio for the three and nine months ended September 30, 2015 decreases to 92% and 80%, respectively.

Subsequent to the quarter end, we have taken additional steps to preserve our balance sheet strength. We have entered into an agreement to sell a portion of our non-operated North Dakota acreage for proceeds of $80 million. In addition, we are further reducing our monthly dividend to $0.03 per share from $0.05 per share, effective with our December 2015 payment. We expect to save approximately $50 million annually with the reduction. These initiatives, coupled with our continuing operational success, will allow us to execute our sustainable strategy for 2016.

Total debt, net of cash, at September 30, 2015 was $1,226.5 million compared to $1,134.9 million at December 31, 2014. Total debt was comprised of $113.5 million of bank indebtedness and $1,115.9 million of senior notes less $2.9 million in cash. At September 30, 2015, we were approximately 11% drawn on our $1.0 billion bank credit facility. The majority of the increase in our reported debt balance at September 30, 2015 was a result of the impact of a weakening Canadian dollar on our U.S. dollar denominated senior notes. On October 1, 2015, we paid the final installment of US$10.8 million on our maturing US$54 million senior notes. We have no additional scheduled debt repayments until June of 2017, with remaining maturities extending to 2026.

Subsequent to the quarter end, we completed a one year extension of our senior, unsecured, covenant-based bank credit facility which now matures on October 31, 2018. As part of the extension, we chose to decrease our bank credit facility to $800.0 million from $1.0 billion based on our capital spending plan for 2016 and our ongoing cost reduction initiatives. Our decision balanced the need for sufficient liquidity for executing our business plan with the associated costs of retaining a largely undrawn bank facility. We expect to realize savings of approximately $1.0 million as a result of the decreased facility size. With over 90% of our total debt comprised of term debt with no repayments until 2017 and an average drawn balance of approximately 9% of the current available capacity on our bank credit facility, we are of the view that the $1.0 billion limit provided excess capacity that is not currently required by the Company. Given our reduced 2016 capital spending plan, we intend to maintain our balance sheet strength by balancing capital spending and dividends with funds flow and non-core asset divestments as we continue to focus our portfolio. Our renewed credit facility also amends the maximum Total Debt to Capitalization ratio to 55%. Drawn fees on the facility 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 September 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.

ENERPLUS 2015 Q3 REPORT 23

The following table lists our financial covenants as at September 30, 2015:

Covenant Description		September 30, 2015

Bank Credit Facility:	Maximum Ratio
Senior Debt to EBITDA	3.5 x	1.8 x
Total Debt to EBITDA	4.0 x	1.8 x
Total Debt to Capitalization(1)	50% – 55%	32%
Senior Notes:	Maximum Ratio
Senior Debt to EBITDA(2)	3.0 x – 3.5 x	1.8 x
Maximum debt to consolidated present value of total proven reserves	60%	40%
	Minimum Ratio
EBITDA to Interest	4.0 x	10.3 x

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 September 30, 2015 were $120.9 million and $676.0 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. Under the renewed credit facility, the maximum ratio increases to 55%.
(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 September 30,				Nine months ended September 30,
($ millions, except per share amounts)		2015		2014		2015		2014

Cash dividends	$	30.9	$	51.1	$	109.2	$	143.8
Stock dividend plan		–		4.3		–		21.8

Total dividends to shareholders	$	30.9	$	55.4	$	109.2	$	165.6

Per weighted average share (Basic)	$	0.15	$	0.27	$	0.53	$	0.81

During the three and nine months ended September 30, 2015 we reported total dividends of $30.9 million ($0.15/share) and $109.2 million ($0.53/share), respectively, compared to $55.4 million ($0.27/share) and $165.6 million ($0.81/share) for the same periods in 2014. For the three and nine months ended September 30, 2015, our cash dividends represented approximately 26% and 28% of funds flow, respectively, compared to 24% and 22% for the same periods in 2014. 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.

To ensure financial flexibility and balance funds flow with capital and dividends we are reducing our monthly dividend to $0.03 per share from $0.05 per share, effective with the December payment. We expect to save approximately $50 million annually. 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.

24 ENERPLUS 2015 Q3 REPORT

Shareholders' Capital

	Nine months ended September 30,
		2015		2014

Share capital ($ millions)	$	3,132.9	$	3,115.5
Common shares outstanding (thousands)		206,496		205,423
Weighted average shares outstanding – basic (thousands)		206,100		204,174
Weighted average shares outstanding – diluted (thousands)		206,100		207,970

During the third quarter of 2015 a total of 272,000 shares (2014 – 655,000) and $6.4 million of additional equity (2014 – $12.2 million) was issued pursuant to the stock option plan, the treasury settled LTI plans and the stock dividend plan. For the nine months ended September 30, 2015 a total of 764,000 shares (2014 – 2,665,000) and $12.7 million of additional equity (2014 – $48.9 million) was issued pursuant to the stock option plan, the treasury settled LTI plans and the stock dividend plan. For further details see Note 14.

At September 30, 2015 we had 206,496,000 shares outstanding (2014 – 205,423,000) and at November 5, 2015 we had 206,496,000 shares outstanding.

2015 GUIDANCE

We have increased our annual production guidance, reduced our capital spending guidance and decreased our operating cost and cash G&A expense guidance. All other guidance has been maintained and is summarized below. This guidance includes the fourth quarter sale of a portion of our non-operated North Dakota property but does not include any additional acquisitions or divestments.

Summary of 2015 Expectations		Target

Capital spending		$510 million (from $540 million)
Average annual production		106,000 BOE/day (from 100,000 – 104,000 BOE/day)
Crude oil and natural gas liquids volumes		46,000 bbls/day (from 44,000 – 46,000 bbls/day)
Average royalty and production tax rate (% of gross sales, before transportation)		21%
Operating expenses		$9.00/BOE (from $9.25/BOE)
Transportation costs		$3.00/BOE
Cash G&A expenses		$2.20/BOE (from $2.25/BOE)

2016 GUIDANCE

This guidance includes the fourth quarter sale of a portion of our non-operated North Dakota property but does not include any additional acquisitions or divestments.

Summary of 2016 Expectations		Target

Capital spending		$350 million
Average annual production		100,000 – 105,000 BOE/day
Crude oil and natural gas liquids volumes		44,000 – 47,000 bbls/day
Average royalty and production tax rate (% of gross sales, before transportation)		22%
Operating expenses		$9.20/BOE
Transportation costs		$3.00/BOE
Cash G&A expenses		$1.90/BOE

ENERPLUS 2015 Q3 REPORT 25

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 September 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 July 1, 2015 and ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ADDITIONAL INFORMATION

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

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", intends", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: expected 2015 and 2016 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our 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 2016 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; expectations regarding our measures to preserve our financial strength, including effectiveness thereof and amounts of anticipated savings 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 September 30, 2015 forward prices: a WTI price of US$49.68/bbl, a NYMEX price of US$2.75/Mcf, an AECO price of $2.66/GJ and a CDN/USD exchange rate of 1.28. Our 2016 guidance is based on the following price assumptions: a WTI price of US$50/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.85/GJ, a CDN/USD exchange rate of 1.33, a Bakken crude oil differential of US$8.00/bbl below WTI and a Marcellus differential of US$1.25/Mcf below NYMEX.

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

26 ENERPLUS 2015 Q3 REPORT

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).

ENERPLUS 2015 Q3 REPORT 27

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Exhibit 99.1

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Exhibit 99.2

STATEMENTS

Condensed Consolidated Balance Sheets

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

Assets
Current Assets
	Cash		$	2,916		$	2,036
	Accounts receivable	3		149,059			199,745
	Deferred financial assets	15		108,145			215,706
	Other current assets			12,742			8,241

				272,862			425,728

Property, plant and equipment:
	Oil and natural gas properties (full cost method)	4		1,567,927			2,632,474
	Other capital assets, net	4		20,101			20,591

	Property, plant and equipment			1,588,028			2,653,065

Goodwill		5		651,171			624,390
Deferred income tax asset		13		816,599			348,117
Deferred financial assets		15		9,423			30,997

Total Assets			$	3,338,083		$	4,082,297

Liabilities
Current liabilities
	Accounts payable	6	$	272,259		$	351,006
	Dividends payable			10,325			18,516
	Current portion of long-term debt	7		14,466			98,933
	Deferred income tax liability	13		22,996			50,805
	Deferred financial liabilities	15		18,930			10,826

				338,976			530,086

Deferred financial liabilities		15		–			2,396
Long-term debt		7		1,215,002			1,037,997
Asset retirement obligation		8		286,027			288,692

				1,501,029			1,329,085

Total Liabilities				1,840,005			1,859,171

Shareholders' Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: September 30, 2015 – 206 million shares December 31, 2014 – 206 million shares		14		3,132,923			3,120,002
Paid-in capital		14		54,562			46,906
Accumulated deficit				(2,046,914	)		(1,039,260	)
Accumulated other comprehensive income/(loss)				357,507			95,478

				1,498,078			2,223,126

Total Liabilities & Equity			$	3,338,083		$	4,082,297

Contingencies		16
Subsequent events		18

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

28 ENERPLUS 2015 Q3 REPORT

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

			Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands) unaudited		Note		2015			2014			2015			2014

Revenues
Oil and natural gas sales, net of royalties		9	$	228,271		$	378,332		$	684,961		$	1,200,997
Commodity derivative instruments gain/(loss)		15		81,032			91,268			111,679			14,602

				309,303			469,600			796,640			1,215,599

Expenses
Production taxes				13,913			21,270			38,946			61,116
Operating				90,405			88,853			254,876			254,728
Transportation				30,879			27,907			85,380			72,870
General and administrative		10		29,028			22,937			85,370			80,240
Depletion, depreciation, amortization and accretion				131,498			159,658			401,251			440,494
Asset impairment		5		321,150			–			1,086,008			–
Interest		11		16,514			15,175			49,668			46,876
Foreign exchange (gain)/loss		12		69,638			30,498			146,184			24,742
Other expense/(income)				70			(953	)		8,597			1,599

				703,095			365,345			2,156,280			982,665

Income/(loss) before taxes				(393,792	)		104,255			(1,359,640	)		232,934
Current income tax expense/(recovery)		13		(16,202	)		(28	)		(16,241	)		11,447
Deferred income tax expense/(recovery)		13		(84,924	)		36,853			(444,983	)		74,063

Net Income/(Loss)			$	(292,666	)	$	67,430		$	(898,416	)	$	147,424

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				115,759			78,459			262,029			80,689

Other Comprehensive Income/(Loss)				115,759			78,459			262,029			83,047

Total Comprehensive Income/(Loss)			$	(176,907	)	$	145,889		$	(636,387	)	$	230,471

Net income/(loss) per share
Basic		14	$	(1.42	)	$	0.33		$	(4.36	)	$	0.72
Diluted		14	$	(1.42	)	$	0.32		$	(4.36	)	$	0.71

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

ENERPLUS 2015 Q3 REPORT 29

Condensed Consolidated Statements of Changes
in Shareholders' Equity

Nine months ended September 30 (CDN$ thousands) unaudited			2015			2014

Share Capital
Balance, beginning of year		$	3,120,002		$	3,061,839
Stock Option Plan – cash			3,205			27,068
Share-based compensation – settled			9,449			–
Stock Option Plan – exercised			267			4,783
Stock Dividend Plan			–			21,837

Balance, end of period		$	3,132,923		$	3,115,527

Paid-in Capital
Balance, beginning of year		$	46,906		$	38,398
Share-based compensation – settled			(9,449	)		–
Stock Option Plan – exercised			(267	)		(4,783	)
Share-based compensation – non-cash			17,372			9,907

Balance, end of period		$	54,562		$	43,522

Accumulated Deficit
Balance, beginning of year		$	(1,039,260	)	$	(1,117,238	)
Net income/(loss)			(898,416	)		147,424
Dividends			(109,238	)		(165,587	)

Balance, end of period		$	(2,046,914	)	$	(1,135,401	)

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			262,029			80,689

Balance, end of period		$	357,507		$	32,350

Total Shareholders' Equity		$	1,498,078		$	2,055,998

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

30 ENERPLUS 2015 Q3 REPORT

Condensed Consolidated Statements of Cash Flows

			Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands) unaudited		Note		2015			2014			2015			2014

Operating Activities
Net income/(loss)			$	(292,666	)	$	67,430		$	(898,416	)	$	147,424
Non-cash items add/(deduct):
	Depletion, depreciation, amortization and accretion			131,498			159,658			401,251			440,494
	Asset impairment	5		321,150			–			1,086,008			–
	Changes in fair value of derivative instruments	15		(26,395	)		(88,689	)		134,842			(81,750	)
	Deferred income tax expense/(recovery)	13		(84,924	)		36,853			(444,983	)		74,063
	Foreign exchange (gain)/loss on debt and working capital	12		64,148			33,863			133,536			35,798
	Share-based compensation	14		7,793			3,413			17,372			9,907
	Amortization of debt issue costs			241			251			721			744
	Asset divestments (gain)/loss			–			–			–			2,798
Derivative settlement on senior notes				–			–			(39,904	)		17,024
Asset retirement obligation expenditures		8		(4,172	)		(3,299	)		(10,631	)		(11,831	)
Changes in non-cash operating working capital		17		5,994			(10,435	)		9,045			(66,710	)

Cash flow from operating activities				122,667			199,045			388,841			567,961

Financing Activities
Proceeds from the issuance of shares		14		–			7,875			3,205			27,068
Cash dividends		14		(30,944	)		(51,088	)		(109,238	)		(143,750	)
Change in bank credit facility				33,192			(236,013	)		33,626			(159,303	)
Issue of/(repayment of) senior notes				–			217,460			(88,897	)		179,562
Derivative settlement on senior notes				–			–			39,904			(17,024	)
Changes in non-cash financing working capital				14			34			(8,191	)		238

Cash flow from financing activities				2,262			(61,732	)		(129,591	)		(113,209	)

Investing Activities
Capital and office expenditures				(89,902	)		(209,197	)		(407,229	)		(633,013	)
Property and land acquisitions				(2,005	)		(3,986	)		(758	)		(17,186	)
Property divestments				11,865			68,931			203,378			185,631
Sale of marketable securities				–			–			–			13,300
Changes in non-cash investing working capital				(40,697	)		5,116			(51,914	)		(5,689	)

Cash flow from investing activities				(120,739	)		(139,136	)		(256,523	)		(456,957	)

Effect of exchange rate changes on cash				(2,276	)		1,929			(1,847	)		1,319

Change in cash				1,914			106			880			(886	)
Cash, beginning of period				1,002			1,998			2,036			2,990

Cash, end of period			$	2,916		$	2,104		$	2,916		$	2,104

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

ENERPLUS 2015 Q3 REPORT 31

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 November 5, 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 nine months ended September 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)		September 30, 2015			December 31, 2014

Accrued receivables	$	101,897		$	136,949
Accounts receivable – trade		27,338			41,618
Current income tax receivable		22,566			23,900
Allowance for doubtful accounts		(2,742	)		(2,722	)

Total accounts receivable	$	149,059		$	199,745

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

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

Oil and natural gas properties	$	13,415,111	$	(11,847,184	)	$	1,567,927
Other capital assets		103,401		(83,300	)		20,101

Total PP&E	$	13,518,512	$	(11,930,484	)	$	1,588,028

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

32 ENERPLUS 2015 Q3 REPORT

5) IMPAIRMENT

a) Impairment of PP&E

		Three months ended September 30,				Nine months ended September 30,
($ thousands)			2015		2014		2015		2014

Oil and natural gas properties:
	Canada cost centre	$	258,600	$	–	$	286,700	$	–
	U.S. cost centre		62,550		–		799,308		–

Total impairment expense		$	321,150	$	–	$	1,086,008	$	–

The impairments for the three and nine months ended September 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 September 30, 2014 through September 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

Q3 2015	$	59.21	1.22	$	66.51	$	3.08	$	3.00
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

b) Goodwill Impairment

Goodwill impairment testing is performed annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We have assessed potential indicators of impairment as at September 30, 2015 and find that no impairment to goodwill is required.

6) ACCOUNTS PAYABLE

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

Accrued payables	$	192,996	$	239,773
Accounts payable – trade		79,263		111,233

Total accounts payable	$	272,259	$	351,006

7) DEBT

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

Current:
	Senior notes	$	14,466	$	98,933

			14,466		98,933

Long-term:
	Bank credit facility	$	113,543	$	79,917
	Senior notes		1,101,459		958,080

			1,215,002		1,037,997

Total debt		$	1,229,468	$	1,136,930

ENERPLUS 2015 Q3 REPORT 33

8) ASSET RETIREMENT OBLIGATION

Enerplus has estimated the present value of its asset retirement obligation to be $286.0 million at September 30, 2015 compared to $288.7 million at December 31, 2014 based on a total undiscounted liability of $702.3 million and $730.9 million, respectively. The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.93% (December 31, 2014 – 5.92%).

($ thousands)		Nine months ended September 30, 2015			Year ended December 31, 2014

Balance, beginning of year	$	288,692		$	291,761
Change in estimates		9,139			4,378
Property acquisitions and development activity		711			1,778
Dispositions		(14,245	)		(4,313	)
Settlements		(10,631	)		(19,409	)
Accretion expense		12,361			14,497

Balance, end of period	$	286,027		$	288,692

9) OIL AND NATURAL GAS SALES

	Three months ended September 30,						Nine months ended September 30,
($ thousands)		2015			2014			2015			2014

Oil and natural gas sales	$	275,663		$	456,215		$	818,173		$	1,455,790
Royalties(1)		(47,392	)		(77,883	)		(133,212	)		(254,793	)

Oil and natural gas sales, net of royalties	$	228,271		$	378,332		$	684,961		$	1,200,997

(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 September 30,				Nine months ended September 30,
($ thousands)			2015		2014		2015		2014

	General and administrative expense	$	22,827	$	18,854	$	64,134	$	58,055
	Share-based compensation expense		6,201		4,083		21,236		22,185

General and administrative expense		$	29,028	$	22,937	$	85,370	$	80,240

11) INTEREST EXPENSE

		Three months ended September 30,				Nine months ended September 30,
($ thousands)			2015		2014		2015		2014

Realized:
	Interest on bank debt and senior notes	$	16,273	$	14,924	$	48,947	$	45,552
Unrealized:
	Cross currency interest rate swap (gain)/loss		–		–		–		580
	Amortization of debt issue costs		241		251		721		744

Interest expense		$	16,514	$	15,175	$	49,668	$	46,876

34 ENERPLUS 2015 Q3 REPORT

12) FOREIGN EXCHANGE

		Three months ended September 30,						Nine months ended September 30,
($ thousands)			2015			2014			2015			2014

Realized:
	Foreign exchange (gain)/loss	$	8,786		$	(2,607	)	$	(18,350	)	$	14,069
Unrealized:
	Translation of U.S. dollar debt and working capital (gain)/loss		64,148			33,863			133,536			35,798
	Cross currency interest rate swap (gain)/loss		–			–			–			(16,130	)
	Foreign exchange derivatives (gain)/loss		(3,296	)		(758	)		30,998			(8,995	)

Foreign exchange (gain)/loss		$	69,638		$	30,498		$	146,184		$	24,742

13) INCOME TAXES

		Three months ended September 30,						Nine months ended September 30,
($ thousands)			2015			2014			2015			2014

Current tax expense/(recovery)
	Canada	$	3		$	(79	)	$	(397	)	$	(453	)
	United States		(16,205	)		51			(15,844	)		11,900

Current tax expense/(recovery)			(16,202	)		(28	)		(16,241	)		11,447

Deferred tax expense/(recovery)
	Canada	$	(62,778	)	$	24,530		$	(99,717	)	$	19,212
	United States		(22,146	)		12,323			(345,266	)		54,851

Deferred tax expense/(recovery)			(84,924	)		36,853			(444,983	)		74,063

Income tax expense/(recovery)		$	(101,126	)	$	36,825		$	(461,224	)	$	85,510

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.

The net deferred income tax asset at September 30, 2015 includes a current deferred income tax liability of $23.0 million (December 31, 2014 – $50.8 million) and a long-term deferred income tax asset of $816.6 million (December 31, 2014 – $348.1 million). We have evaluated our overall net deferred income tax asset of $793.6 million as at September 30, 2015 (December 31, 2014 – $297.3 million) and expect that we will have sufficient future taxable income to realize the benefit of this asset.

14) SHAREHOLDERS' EQUITY

a) Share Capital

		Nine months ended September 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	530		9,449	–		–
	Stock Option Plan – exercised	–		267	–		4,978
	Stock Dividend Plan(1)	–		–	1,030		21,835

Balance, end of period		206,496	$	3,132,923	205,732	$	3,120,002

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

ENERPLUS 2015 Q3 REPORT 35

b) Dividends

	Three months ended September 30,				Nine months ended September 30,
($ thousands)		2015		2014		2015		2014

Cash dividends	$	30,944	$	51,088	$	109,238	$	143,750
Stock dividends(1)		–		4,350		–		21,837

Dividends to shareholders	$	30,944	$	55,438	$	109,238	$	165,587

(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 September 30,						Nine months ended September 30,
($ thousands)			2015			2014			2015		2014

Cash:
	Long-term incentive plans expense	$	(3,565	)	$	(5,174	)	$	2,458	$	12,338
Non-cash:
	Long-term incentive plans expense		7,649			2,815			16,698		6,506
	Stock option plan expense		144			598			674		3,401
	Equity swap (gain)/loss		1,973			5,844			1,406		(60	)

Share-based compensation expense		$	6,201		$	4,083		$	21,236	$	22,185

(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 nine months ended September 30, 2015:

For the nine months ended September 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		987		1,447		2,511
Vested	(168	)	(268	)	(19	)	(213	)	(317	)	(985	)
Forfeited	(10	)	(29	)	–		(36	)	(142	)	(217	)

Balance, end of period	228		101		180		1,248		1,763		3,520

Cash-settled LTI Plans

For the three and nine months ended September 30, 2015 the Company recorded a cash share-based compensation recovery of $3.6 million and an expense of $2.5 million, respectively (2014 – $5.2 million recovery and $12.3 million expense). For the same periods, the Company made cash payments of $3.0 and $8.6 million, respectively, related to its cash-settled plans (September 30, 2014 – $2.0 million and $13.8 million).

36 ENERPLUS 2015 Q3 REPORT

The following table summarizes the cumulative cash 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 September 30, 2015 ($ thousands, except for years)		PSU(1)		RSU		DSU		Total

Cumulative recognized share-based compensation expense	$	3,609	$	785	$	1,526	$	5,920
Unrecognized share-based compensation expense		328		127		–		455

Intrinsic value	$	3,937	$	912	$	1,526	$	6,375

Weighted-average remaining contractual term (years)		0.3		0.4		–

(1): Includes estimated performance multipliers.

Equity-settled LTI Plans

For the three and nine months ended September 30, 2015 the Company recorded non-cash long-term incentive plans expense of $7.7 million and $16.7 million, respectively (2014 – $2.8 million and $6.5 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 September 30, 2015 ($ thousands, except for years)		PSU(1)		RSU		Total

Cumulative recognized share-based compensation expense	$	5,761	$	10,867	$	16,628
Unrecognized share-based compensation expense		8,662		12,338		21,000

Fair value	$	14,423	$	23,205	$	37,628

Weighted-average remaining contractual term (years)		1.9		1.4

(1): Includes estimated performance multipliers.

(ii) Stock Option Plan

The Company did not grant any stock options for the three and nine months ended September 30, 2015. The following table summarizes the stock option plan activity for the period ended September 30, 2015:

Period ended September 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	(774	)		19.96

Options outstanding, end of period		9,360		$	18.67

Options exercisable, end of period		8,087		$	19.38

At September 30, 2015 8,087,000 options were exercisable at a weighted average reduced exercise price of $19.38 with a weighted average remaining contractual term of 3.5 years, giving an aggregate intrinsic value of nil (2014 – 4 years and $17.4 million). The intrinsic value of options exercised for the three and nine months ended September 30, 2015 was nil and $0.2 million, respectively (September 30, 2014 – $4.3 million and $12.4 million).

At September 30, 2015 the total share-based compensation expense related to non-vested options not yet recognized was $0.2 million. The expense is expected to be recognized in net income over a weighted-average period of 0.4 years.

ENERPLUS 2015 Q3 REPORT 37

d) Paid-in Capital

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

($ thousands)		Nine months ended September 30, 2015			Year Ended December 31, 2014

Balance, beginning of year	$	46,906		$	38,398
Share-based compensation – settled		(9,449	)		–
Stock Option Plan – exercised		(267	)		(4,978	)
Share-based compensation – non-cash		17,372			13,486

Balance, end of period	$	54,562		$	46,906

e) Basic and Diluted Earnings Per Share

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

		Three months ended September 30,					Nine months ended September 30,
(thousands, except per share amounts)			2015			2014		2015			2014

Net income/(loss)		$	(292,666	)	$	67,430	$	(898,416	)	$	147,424
Weighted average shares outstanding – Basic			206,243			205,164		206,100			204,174
Dilutive impact of share-based compensation(1)			–			3,933		–			3,796

Weighted average shares outstanding – Diluted			206,243			209,097		206,100			207,970

Net income/(loss) per share
	Basic	$	(1.42	)	$	0.33	$	(4.36	)	$	0.72
	Diluted(1)	$	(1.42	)	$	0.32	$	(4.36	)	$	0.71

(1): For the three and nine months ended September 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 September 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 September 30, 2015 senior notes had a carrying value of $1,115.9 million and a fair value of $1,225.6 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 liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

38 ENERPLUS 2015 Q3 REPORT

The following table summarizes the change in fair value for the three and nine months ended September 30, 2015 and 2014:

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

Cross Currency Interest Rate Swap
	Interest	$	–		$	–		$	–		$	(580	)	Interest expense
	Foreign Exchange		–			–			–			16,130		Foreign exchange
Foreign Exchange Derivatives			3,296			758			(30,998	)		8,995		Foreign exchange
Electricity Swaps			(1,855	)		22			(141	)		204		Operating expense
Equity Swaps			(1,973	)		(5,844	)		(1,406	)		60		General and administrative expense
Commodity Derivative Instruments:
	Oil		35,135			82,874			(71,909	)		48,671		Commodity derivative
	Gas		(8,208	)		10,879			(30,388	)		8,270		instruments

Total		$	26,395		$	88,689		$	(134,842	)	$	81,750

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

	Three months ended September 30,					Nine months ended September 30,
($ thousands)		2015		2014			2015			2014

Change in fair value gain/(loss)	$	26,927	$	93,753		$	(102,297	)	$	56,941
Net realized cash gain/(loss)		54,105		(2,485	)		213,976			(42,339	)

Commodity derivative instruments gain/(loss)	$	81,032	$	91,268		$	111,679		$	14,602

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

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

Foreign Exchange Derivatives		$	3,444	$	–	$	12,595	$	1,616	$	28,665	$	8,434	$	–
Electricity Swaps			–		–		1,508		–		–		1,368		–
Equity Swaps			–		–		4,827		–		–		1,024		2,396
Commodity Derivative Instruments:
	Oil		85,855		9,423		–		167,187		–		–		–
	Gas		18,846		–		–		46,903		2,332		–		–

Total		$	108,145	$	9,423	$	18,930	$	215,706	$	30,997	$	10,826	$	2,396

ENERPLUS 2015 Q3 REPORT 39

c) Risk Management

(i) Market Risk

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

Commodity Price Risk:

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

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

Crude Oil Instruments:

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

Oct 1, 2015 – Nov 30, 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	)
Dec 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	2,000	(3.05	)
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	3,000	(14.03	)
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	3,000	(14.03	)

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

40 ENERPLUS 2015 Q3 REPORT

Natural Gas Instruments:

Instrument Type	MMcf/day	US$/Mcf

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

Electricity Instruments:

Instrument Type	MWh	CDN$/MWh

Oct 1, 2015 – Dec 31, 2015
AESO Power Swap	16.0	48.30
Jan 1, 2016 – Dec 31, 2016
AESO Power Swap	15.0	46.60
Jan 1, 2016 – Dec 31, 2016
AESO Power Swap	6.0	44.38

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

Physical Contracts:

Instrument Type	MMcf/day	US$/Mcf

Oct 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.

ENERPLUS 2015 Q3 REPORT 41

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 September 30, 2015 we have US$24 million per month hedged for the remainder of 2015 at an average US/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 into foreign exchange swaps on US$54.0 million of notional debt at an average US/CDN exchange rate of 1.02. The remaining US$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 September 30, 2015 approximately 91% of Enerplus' debt was based on fixed interest rates and 9% was based on floating interest rates. At September 30, 2015 Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing between 2015 and 2017 and has effectively fixed the final settlement cost on 470,000 shares at weighted average price of $16.89 per share.

(ii) Credit Risk

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.

Enerplus mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties' credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

Enerplus' maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At September 30, 2015 approximately 59% of Enerplus' marketing receivables were with companies considered investment grade.

At September 30, 2015 approximately $3.2 million or 2% of Enerplus' total accounts receivable were aged over 120 days and considered past due. The majority of these accounts are due from various joint venture partners. Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts of future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectable the account is written off with a corresponding charge to the allowance account. Enerplus' allowance for doubtful accounts balance at September 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 September 30, 2015 Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

42 ENERPLUS 2015 Q3 REPORT

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.

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

	Three months ended September 30,						Nine months ended September 30,
($ thousands)		2015			2014			2015			2014

Accounts receivable	$	1,347		$	6,858		$	20,043		$	(13,019	)
Other current assets		9,657			(5,754	)		(5,220	)		(5,210	)
Accounts payable		(5,010	)		(11,539	)		(5,778	)		(48,481	)

	$	5,994		$	(10,435	)	$	9,045		$	(66,710	)

b) Other

	Three months ended September 30,						Nine months ended September 30,
($ thousands)		2015			2014			2015			2014

Income taxes paid/(received)	$	(972	)	$	(254	)	$	(20,169	)	$	18,133
Interest paid	$	6,428		$	4,138		$	38,846		$	32,826

18) SUBSEQUENT EVENTS

The following events occurred subsequent to September 30, 2015:

Enerplus entered into an agreement to sell a portion of its non-operated interest in North Dakota crude oil assets for proceeds of approximately $80 million, before closing adjustments. This divestment is expected to close in 2015.

Enerplus' Board of Directors approved a reduction in its monthly dividend from $0.05 per share to $0.03 per share, effective with the December dividend.

Enerplus extended its senior unsecured bank credit facility to October 31, 2018, and requested a reduction in the committed capacity from $1 billion to $800 million.

ENERPLUS 2015 Q3 REPORT 43

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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 September 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 July 1, 2015 and ended on September 30, 2015 that has materially affected, or is reasonably likely to materially affect, the issuer's ICFR.


Date: November 6, 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, JODI JENSON LABRIE, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:

1.

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

ICFR — material weakness relating to design: N/A

5.3

Limitation on scope of design: N/A

6.


Date: November 6, 2015
(signed by) Jodi Jenson Labrie Senior Vice President and Chief Financial Officer Enerplus Corporation

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Exhibit 99.4

FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE

This regulatory filing also includes additional resources:
a2226480zex-99_1.pdf
a2226480zex-99_2.pdf

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