Report of Foreign Issuer (6-k)

ERF Enerplus Corporation

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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, 2014

COMMISSION FILE NUMBER 1-15150

The Dome Tower
Suite 3000, 333 - 7^th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200

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


Form 20-F o		Form 40-F ý

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


Yes o		No ý

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


Yes o		No ý

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


Yes o		No ý

EXHIBIT INDEX

EXHIBIT 99.1 — Enerplus Third Quarter Report for the Period Ending September 30, 2014

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 7, 2014

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EXHIBIT INDEX
SIGNATURE

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Exhibit 99.1

Selected Financial Results

SELECTED FINANCIAL RESULTS	Three months ended September 30,						Nine months ended September 30,
		2014			2013			2014			2013

Financial (000's)
Funds Flow	$	212,779		$	196,187		$	646,502		$	573,492
Cash and Stock Dividends		55,438			54,405			165,587			162,199
Net Income		67,430			(3,720	)		147,424			18,350
Debt Outstanding – net of cash		1,091,110			964,577			1,091,110			964,577
Capital Spending		207,838			145,811			630,027			458,402
Property and Land Acquisitions		3,986			15,792			17,186			71,451
Property Dispositions		68,931			124,462			185,631			197,086
Debt to Trailing 12-Month Funds Flow		1.3x			1.2x			1.3x			1.2x
Financial per Weighted Average Shares Outstanding
Funds Flow	$	1.04		$	0.98		$	3.17		$	2.87
Net Income (Basic)		0.33			(0.02	)		0.72			0.09
Weighted Average Number of Shares Outstanding (000's)		205,164			201,117			204,174			200,002
Selected Financial Results per BOE⁽¹⁾⁽²⁾
Oil & Natural Gas Sales⁽³⁾	$	46.13		$	53.61		$	50.66		$	49.67
Royalties and Production Taxes		(10.36	)		(11.91	)		(11.31	)		(10.46	)
Commodity Derivative Instruments		(0.26	)		(1.30	)		(1.52	)		0.42
Operating Costs		(10.67	)		(10.58	)		(10.28	)		(10.52	)
General and Administrative		(1.97	)		(2.48	)		(2.08	)		(2.63	)
Share-Based Compensation		0.54			(0.60	)		(0.44	)		(0.58	)
Interest, Foreign Exchange and Other Expenses		(1.18	)		(1.78	)		(1.48	)		(1.78	)
Taxes		–			(0.65	)		(0.40	)		(0.33	)

Funds Flow	$	22.23		$	24.31		$	23.15		$	23.79

SELECTED OPERATING RESULTS	Three months ended September 30,				Nine months ended September 30,
		2014		2013		2014		2013

Average Daily Production⁽²⁾
Crude oil (bbls/day)		40,332		38,883		39,328		38,426
NGLs (bbls/day)		3,869		2,985		3,591		3,357
Natural gas (Mcf/day)		359,007		275,164		356,288		279,212
Total (BOE/day)		104,035		87,729		102,300		88,318
% Natural Gas		58%		52%		58%		53%
Average Selling Price⁽²⁾⁽³⁾
Crude oil (per bbl)	$	86.49	$	96.30	$	90.91	$	86.05
NGLs (per bbl)		44.85		49.88		53.01		51.48
Natural gas (per Mcf)		3.22		2.96		4.04		3.26
Net Wells drilled		19		15		63		50

(1): Non-cash amounts have been excluded.
(2): Based on Company interest production volumes. See "Basis of Presentation" section in the following MD&A.
(3): Net of oil and gas transportation costs, but before royalties and the effects of commodity derivative instruments.

ENERPLUS 2014 Q3 REPORT 1

	Three months ended September 30,				Nine months ended September 30,
Average Benchmark Pricing		2014		2013		2014		2013

WTI crude oil (US$/bbl)	$	97.17	$	105.82	$	99.61	$	98.14
AECO – monthly index (CDN$/Mcf)		4.22		2.82		4.55		3.16
AECO – daily index (CDN$/Mcf)		4.02		2.43		4.81		3.05
NYMEX – last day (US$/Mcf)		4.06		3.58		4.55		3.67
USD/CDN exchange rate		1.09		1.04		1.09		1.02

Share Trading Summary For the three months ended September 30, 2014		*CDN – ERF** (CDN$)		U.S. – ERF** (US$)

High	$	27.05	$	25.37
Low	$	20.21	$	18.45
Close	$	21.26	$	18.97

*: TSX and other Canadian trading data combined.
**: NYSE and other U.S. trading data combined.

2014 Dividends per Share Payment Month		CDN$		US$⁽¹⁾

First Quarter Total	$	0.27	$	0.24

Second Quarter Total	$	0.27	$	0.24

July	$	0.09	$	0.08
August	$	0.09	$	0.08
September	$	0.09	$	0.08

Third Quarter Total	$	0.27	$	0.24

Total Year-to-Date	$	0.81	$	0.72

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

2 ENERPLUS 2014 Q3 REPORT

PRESIDENT'S MESSAGE

Through the third quarter of 2014, Enerplus continued to deliver consistent, strong operational and financial performance. Despite a decline in both crude oil and natural gas prices, both funds flow and production were maintained quarter over quarter. We also continued to execute on our non-core divestment strategy, successfully completing two transactions, further strengthening our financial position.

Daily production averaged approximately 104,000 BOE, essentially unchanged from the second quarter. Crude oil and natural gas liquids production increased again in the third quarter to average 44,200 barrels per day, up 700 barrels over the second quarter. We continue to achieve strong performance from our Bakken/Three Forks properties in North Dakota with production increasing by approximately 1,600 BOE per day. Natural gas production was maintained quarter over quarter despite an average of 3,000 – 4,000 BOE per day of Marcellus production being temporarily curtailed due to pipeline maintenance and low natural gas prices in the region.

We continued to execute our capital spending program with discipline in conjunction with a solid financial plan. During the third quarter, we invested $208 million on development drilling activities. Our U.S. assets attracted the majority of our capital spending during the quarter, with roughly two thirds of the capital, drilling and on-stream activity attributable to the Bakken and the Marcellus. In total, we drilled 19.3 net wells and brought 17.3 net wells on-stream across our portfolio.

Despite the drop in commodity prices, funds flow was maintained quarter over quarter at $213 million or $1.04 per share. As previously announced, with the strength of our balance sheet and the improved sustainability of our business, we elected to suspend our Stock Dividend Program ("SDP"). Our current dividend is at an affordable level representing 26% of funds flow. Suspension of the SDP will reduce dilution and help to improve our per share metrics in the future.

We continued to execute on our divestment strategy during the quarter. On September 30, 2014 we closed the sale of approximately 1,900 BOE/day of non-operated production in Canada, 75% weighted to natural gas. We also sold an additional 1,200 BOE/day of Canadian non-operated production (90% weighted to natural gas) which closed in early November. The total proceeds from these transactions are expected to be approximately $91 million reflecting attractive metrics of approximately $30,000 per flowing barrel of production that is predominately natural gas. We intend to continue to look for opportunities to rationalize non-core production, providing us with the opportunity to accelerate spending on our core assets while maintaining our financial strength.

Our non-core divestment activities have generated proceeds of over $200 million year-to-date in 2014. We have continued to meet or surpass our production guidance despite the sale of approximately 3,500 BOE per day of production. As a result of the success of our divestment program, we have redeployed a portion of these proceeds to advance opportunities within our core properties. We have accelerated some of our 2015 activity into the fourth quarter of 2014, particularly in the Wilrich and at Fort Berthold. We anticipate this will have only a modest impact in 2014 but will bring additional production on-stream earlier in 2015. We plan to spend an additional $30 million this year, and are adjusting our full-year capital spending to $830 million.

Production performance year-to-date has been strong, despite the sale of non-core production and curtailed production volumes from the Marcellus. We are increasing the low end of our annual production range and now expect full year production to average between 102,000 – 104,000 BOE per day. The low end of this range largely reflects the risk of additional curtailment in the Marcellus in the fourth quarter. To date in the fourth quarter, we have continued to see our crude oil volumes grow as a result of our development activity at Fort Berthold and expect to achieve our full-year liquids target of 44,000 barrels per day.

ENERPLUS 2014 Q3 REPORT 3

Production and Capital Spending

	Three months ended September 30, 2014			Nine months ended September 30, 2014
	Average Production Volumes		Capital Spending ($ millions)	Average Production Volumes		Capital Spending ($ millions)

Crude Oil & NGLs (BOE/day)
Canada	19,415	$	37	19,398	$	128
United States	24,786		96	23,521		255

Total Crude Oil & NGLs (BOE/day)	44,201	$	133	42,919	$	383

Natural Gas (Mcf/day)
Canada	154,855	$	18	154,306	$	115
United States	204,152		57	201,982		132

Total Natural Gas (Mcf/day)	359,006	$	75	356,288	$	247

Company Total (BOE/day)	104,035	$	208	102,300	$	630

Net Drilling Activity – for the three months ended September 30, 2014

	Horizontal Wells	Wells Pending Completion/ Tie-in *	Wells On- stream**	Dry & Abandoned Wells

Crude Oil
Canada	3.4	2.2	5.5	–
United States	6.6	6.6	5.6	–

Total Crude Oil	10.0	8.8	11.1	–

Natural Gas
Canada	2.1	1.4	0.8	–
United States	7.2	6.9	5.4	–

Total Natural Gas	9.3	8.3	6.2	–

Company Total	19.3	17.1	17.3	–

*: Wells drilled during the quarter that are pending potential completion/tie-in or abandonment as at September 30, 2014.
**: Total wells brought on-stream during the quarter regardless of when they were drilled.

Asset Activity

Drilling activity continued at a brisk pace in Fort Berthold during the third quarter with 6.6 net wells drilled and 5.6 net wells brought on-stream. Production grew again to average 22,400 BOE per day, up almost 1,600 BOE per day from the second quarter. Year-to-date, we have continued to drill into both the Bakken and Three Forks zones with 10 operated wells and 2.4 net non-operated wells brought on-stream. Production performance has continued to improve as a result of our completion optimization activity. The 30 day initial production rates on our two mile horizontal wells brought on-stream in 2014 have averaged 1,725 barrels per day, 20% above our high expected ultimate recovery type curve. We are also seeing an improvement of over 10% in the 60 day production rates which have averaged approximately 1,400 barrels per day.

In the Marcellus, drilling activity continued with 7.2 net wells drilled and 5.4 net wells brought on-stream. Continued production growth and the shortage of takeaway capacity continued to put pressure on basis differentials in the region. Our Marcellus production received a discount of US$1.72 per Mcf to the NYMEX benchmark price during the quarter. As a result of lower prices in the region, combined with pipeline maintenance, 3,000 – 4,000 BOE per day of production was intentionally curtailed during the quarter. Despite this curtailment, production from the Marcellus was essentially unchanged from the second quarter, averaging 187 MMcf per day. Plans are currently underway to slow our pace of activity, moving from a four-rig program to a two-rig program. As a result, we expect capital spending on our Marcellus assets in the fourth quarter to be meaningfully lower than in the third quarter.

As discussed earlier in the year, Enerplus has drilled and completed two horizontal Duvernay wells in the Willesden Green area of central Alberta. Our initial horizontal well at 1-7-45-5W5M was completed in the first quarter of 2014 with a 13 stage hybrid slickwater frac. The well was subsequently shut-in for installation of surface equipment and pipeline tie-in. In late June, we brought this well on production achieving a

4 ENERPLUS 2014 Q3 REPORT

30 day initial production rate of 535 BOE per day including 2.24 MMcf per day of sales gas with 162 barrels per day of total liquids, 53% condensate.

Our second horizontal well at 15-8-46-9W5M was completed in the second quarter of this year with a 14 stage hybrid slickwater frac. This well was also shut-in while surface equipment and pipelines were installed to a third party gas plant and oil battery in the area. We brought this well on-stream in early October and during the first 30 days of production, it has averaged an estimated 700 BOE per day including 1.75 MMcf per day of sales gas, with 410 barrels per day of liquids, roughly 85% condensate.

Both wells have met our expectations on liquids content based upon our geotechnical analysis. The cost of these wells was higher than we expected, particularly on the completions, which is similar to what others have experienced in this deep, over-pressured play. We see a number of opportunities to increase drilling and completion efficiencies going forward, particularly with multi-well pads. Further evaluation of these wells over the coming months is required in order to determine our next steps.

Outlook

Despite the current decline in crude oil prices, Enerplus is very well positioned. Based upon our revised production guidance, we expect to deliver above-average production growth of 13% per share in 2014. Our balance sheet is very strong. Our dividend payout is conservative and our debt-to-trailing 12 month funds flow ratio was 1.3 times at the end of the quarter and we have virtually all of our $1 billion revolving line of credit available. We also have a significant portion of our crude oil production hedged for the remainder of 2014 and into 2015 at prices well above the current market. We anticipate that these positions will provide strong funds flow protection through the fourth quarter and into 2015, lending support for our plans for the remainder of this year and next.

Our preliminary plans for 2015 target continued production growth of 5%-10% per share with a modestly lower capital spending program than in 2014. We have a significant portfolio of economic development opportunities in both crude oil and natural gas that are expected to provide us with organic growth potential for many years. We expect to maintain our strong financial position and will continue to apply discipline to our capital spending program, ensuring that our plans are affordable and that our business is sustainable.

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

ENERPLUS 2014 Q3 REPORT 5

MD&A

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

The following discussion and analysis of financial results is dated November 6, 2014 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, 2014 and 2013 (the "Interim Financial Statements");
•: the audited consolidated financial statements of Enerplus as at December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 (the "Financial Statements"); and
•: our MD&A for the year ended December 31, 2013 (the "Annual MD&A").

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

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.

BASIS OF PRESENTATION

The Interim Financial Statements and notes have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") including the prior period comparatives. All amounts are stated in Canadian dollars unless otherwise specified.

In accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under IFRS, 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 revenue (net of transportation), less royalties, production taxes and cash operating costs.

"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 but 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		2014		2013			2014		2013

Cash flow from operating activities	$	199,045	$	218,170		$	567,961	$	574,828
Asset retirement obligation expenditures		3,299		3,701			11,831		10,036
Changes in non-cash operating working capital		10,435		(25,684	)		66,710		(11,372	)

Funds flow	$	212,779	$	196,187		$	646,502	$	573,492

6 ENERPLUS 2014 Q3 REPORT

"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.

"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 dividends to shareholders, net of our Stock Dividend Program ("SDP") proceeds, plus capital spending (including office capital) divided by funds flow.

OVERVIEW

Production for the third quarter averaged 104,035 BOE/day, consistent with the prior quarter and an increase of 19% compared to the same period in 2013. Crude oil and natural gas liquids production grew by 2% compared to the prior quarter, while natural gas volumes were essentially flat. Low natural gas prices and pipeline maintenance resulted in production curtailments of approximately 3,000-4,000 BOE/day in the Marcellus during the quarter. Despite these interruptions, average production volumes for the year to date are ahead of expectations and we have increased our guidance again for 2014 to 102,000-104,000 BOE/day from 100,000-104,000 BOE/day.

Our capital spending program continued to focus on our core development areas, with $207.8 million spent in the third quarter. As discussed in our second quarter release, the successful divestment of approximately $91.0 million of non-core assets in the second half of 2014 has provided us with additional flexibility and we have redeployed a portion of the divestment proceeds to accelerate our 2015 capital program in our core areas. Accordingly, we have increased our capital spending guidance for 2014 to $830 million from $800 million.

Funds flow for the third quarter totaled $212.8 million compared to $213.2 million in the second quarter and $196.2 million in the same period in 2013. In the third quarter our funds flow was impacted by lower commodity prices however this was partially offset by cash share-based compensation recoveries given the industry wide sell off in equities. Lower commodity prices at quarter end resulted in a $93.8 million non-cash gain on our commodity derivatives which contributed to a nearly 70% increase in our net income compared to the second quarter.

Cash general and administrative expenses for the quarter of $1.97/BOE were consistent with the second quarter. Operating costs increased to $10.67/BOE, compared to $10.09/BOE in the prior quarter, due to production curtailments on our lower operating cost Marcellus properties along with seasonal well servicing and higher repairs and maintenance costs. Based on continued production curtailments in the Marcellus throughout the fourth quarter, we are reverting to our original 2014 operating costs guidance of $10.25/BOE from $10.10/BOE.

Although oil prices declined significantly during the quarter, we continue to maintain a strong balance sheet and financial flexibility. During the quarter, we closed a US$200 million private placement of 3.79%, 10 year average life senior notes and used the proceeds to repay outstanding bank debt. At September 30, 2014 only 5% of our $1 billion credit facility was drawn and our trailing 12 month debt to funds flow ratio was 1.3x. We also have a strong hedge position in place with approximately 64% of our anticipated remaining 2014 crude oil production hedged at a price of $95.29, and approximately 38% of our anticipated 2015 crude oil production hedged at $93.68.

RESULTS OF OPERATIONS

Production

Production levels were maintained in the third quarter with production of 104,035 BOE/day despite production curtailments that averaged 3,000-4,000 BOE/day over the quarter due to decreased natural gas prices and pipeline maintenance in the Marcellus. Our Fort Berthold crude oil production grew by 6% from the prior quarter with our ongoing development program more than fully offsetting the decline in other crude oil assets.

Compared to the third quarter of 2013, production increased 19% or 16,306 BOE/day. Natural gas volumes grew by approximately 30% due to our ongoing development activity in the Marcellus combined with the fourth quarter 2013 acquisition of additional working interests in our existing Marcellus properties. Over the same period, our crude oil volumes increased by approximately 4% due to growth in our Fort Berthold production volumes.

Our production mix was unchanged from the previous quarter, with natural gas being 58% of production and crude oil and natural gas liquids making up 42% of production.

ENERPLUS 2014 Q3 REPORT 7

Average daily production volumes for the three and nine months ended September 30, 2014 and 2013 are outlined below:

	Three months ended September 30,			Nine months ended September 30,
Average Daily Production Volumes	2014	2013	% Change	2014	2013	% Change

Crude oil (bbls/day)	40,332	38,883	4%	39,328	38,426	2%
Natural gas liquids (bbls/day)	3,869	2,985	30%	3,591	3,357	7%
Natural gas (Mcf/day)	359,007	275,164	30%	356,288	279,212	28%

Total daily sales (BOE/day)	104,035	87,729	19%	102,300	88,318	16%

Based on our year to date performance, we have revised our 2014 annual average production guidance to 102,000-104,000 BOE/day from 100,000-104,000 BOE/day. The lower end of the guidance range assumes ongoing production curtailments in the Marcellus throughout the fourth quarter. This guidance also includes the impact of the September 30, 2014 non-core asset disposition of 1,900 BOE/day and the divestment of non-core gas weighted properties with production of approximately 1,200 BOE/day in the fourth quarter.

Our crude oil and natural gas liquids production has been strong in October. We have just finished drilling and completing a five well pad in North Dakota that we expect to have tied-in by early November. We expect our crude oil and natural gas liquids production to increase to approximately 47,000 BOE/day for the fourth quarter and continue to expect average annual crude oil and natural gas liquids production to grow by 5% from 2013 to average 44,000 BOE/day.

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, 2014 and 2013 and quarterly average prices from the third quarter of 2014 to the third quarter of 2013.

		Nine months ended September 30,
Pricing (average for the period)			2014			2013			Q3 2014			Q2 2014			Q1 2014			Q4 2013			Q3 2013

Benchmarks
	WTI crude oil (US$/bbl)	$	99.61		$	98.14		$	97.17		$	102.99		$	98.68		$	97.46		$	105.82
	AECO natural gas – monthly index (CDN$/Mcf)		4.55			3.16			4.22			4.68			4.76			3.16			2.82
	AECO natural gas – daily index (CDN$/Mcf)		4.81			3.05			4.02			4.69			5.71			3.53			2.43
	NYMEX natural gas – last day (US$/Mcf)		4.55			3.67			4.06			4.67			4.94			3.60			3.58
	US/CDN exchange rate		1.09			1.02			1.09			1.09			1.10			1.05			1.04
Enerplus selling price ⁽¹⁾
	Crude oil (CDN$/ bbl)	$	90.91		$	86.05		$	86.49		$	94.90		$	91.48		$	77.77		$	96.30
	Natural gas liquids (CDN$/ bbl)		53.01			51.48			44.85			49.98			66.30			54.26			49.88
	Natural gas (CDN$/ Mcf)		4.04			3.26			3.22			4.02			4.93			3.26			2.96

Average differentials
	MSW Edmonton – WTI (US$/bbl)	$	(7.44	)	$	(5.11	)	$	(7.93	)	$	(6.13	)	$	(8.25	)	$	(14.93	)	$	(4.72	)
	WCS Hardisty – WTI (US$/bbl)		(21.12	)		(22.86	)		(20.18	)		(20.04	)		(23.13	)		(32.20	)		(17.48	)
	Brent Futures (ICE) – WTI (US$/bbl)		7.40			10.40			6.25			6.75			9.19			11.86			3.83
	AECO monthly – NYMEX (US$/Mcf)		(0.40	)		(0.62	)		(0.18	)		(0.38	)		(0.63	)		(0.60	)		(0.86	)
Enerplus realized differentials⁽¹⁾
	Canada crude oil – WTI (US$/bbl)	$	(20.45	)	$	(19.96	)	$	(21.78	)	$	(17.80	)	$	(20.70	)	$	(30.73	)	$	(15.18	)
	Canada natural gas – NYMEX (US$/Mcf)		(0.54	)		(0.77	)		(0.55	)		(0.71	)		(0.31	)		(0.63	)		(1.06	)
	Bakken crude oil – WTI (US$/bbl)		(13.78	)		(8.84	)		(14.72	)		(14.55	)		(11.85	)		(17.47	)		(11.41	)
	Marcellus natural gas – NYMEX (US$/Mcf)		(1.38	)		(0.25	)		(1.72	)		(1.50	)		(0.88	)		(0.50	)		(0.52	)

(1): Net of oil and gas transportation costs, but before the effects of royalties and commodity derivative instruments.

8 ENERPLUS 2014 Q3 REPORT

Crude Oil and Natural Gas Liquids

Our crude oil selling price decreased 9% from the prior quarter as a result of lower benchmark prices and widening differentials. WTI crude oil averaged US$97.17/bbl during the third quarter, down almost US$6.00/bbl from the previous period. Global prices declined steadily due to a combination of seasonal refinery turnarounds reducing demand and higher than anticipated global oil production, primarily in North America and Libya. WTI exited September at US$91.16/bbl and continued to weaken in the fourth quarter.

Light sweet crude oil differentials in Canada weakened considerably during the third quarter with mixed sweet blend (MSW) differentials averaging US$7.93/bbl below WTI as a result of continued apportionment on the Canadian pipeline systems decreasing takeaway capacity. The market continues to await the start of the Line 9 pipeline reversal from Sarnia, Ontario to Montreal, Quebec, which is now delayed until early 2015. Once operational, this reversal will provide access to refineries in Eastern Canada and may provide support for light sweet crude prices. In the US, delays in the startup of the Pony Express pipeline from Guernsey, Wyoming to Cushing, Oklahoma continued to restrict takeaway capacity and negatively impact our realized Bakken differentials in the field, which averaged US$14.72/bbl below WTI for the quarter. Western Canadian Select (WCS) heavy oil differentials remained steady at US$20.18/bbl below WTI but began to strengthen near the end of the quarter as the Flanagan South pipeline project from Pontiac, Illinois to Cushing, Oklahoma began purchasing line fill prior to start-up in the fourth quarter.

Natural Gas

Our selling price decreased 20% compared to the second quarter as a result of lower benchmark prices and widening differentials in the Marcellus region. U.S. natural gas prices continued to fall throughout the third quarter as a result of cooler than average summer weather. This led to significantly higher than expected storage injections across most regions and contributed to NYMEX prices falling by over US$0.60/Mcf, averaging US$4.06/Mcf in the third quarter.

In Canada, the AECO differential to NYMEX narrowed to US$0.18/Mcf below NYMEX during the third quarter, compared to US$0.38/Mcf in the second quarter, given the slower pace of storage refill in western Canada. We continue to maintain a balanced mix of AECO basis, month and day index price exposures in our Canadian gas portfolio, with our index exposure split almost evenly between month and day AECO indices.

Natural gas prices in the Marcellus continued to trade at a significant discount to NYMEX, as Marcellus and Utica production continued to outpace growth in pipeline takeaway capacity. Our production is priced primarily off of northeast Pennsylvania and Dominion South Point prices. Scheduled maintenance across a number of interstate pipelines resulted in volatility of spot prices throughout northeast Pennsylvania, with spot prices in the region averaging approximately US$2.00/Mcf below NYMEX for the quarter. With approximately 55% of our Marcellus production during the quarter exposed to spot prices in northeast Pennsylvania and approximately 36% exposed to Dominion South Point, we realized a Marcellus price differential of US$1.72/Mcf below NYMEX. We continue to expect wide differentials in the Marcellus for the remainder of the year, although new pipeline capacity coming on-stream on November 1, 2014 may provide some relief.

Foreign Exchange

The majority of our oil and 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. After regaining some ground in the second quarter, the Canadian dollar weakened by nearly 5% in the third quarter and exited September near year to date lows. During the third quarter, we continued to enter into foreign exchange costless collars on our oil and gas sales to hedge a floor exchange rate on a portion of our U.S. dollar denominated oil and gas sales and to participate in some upside potential in the event the Canadian dollar continues to weaken.

As of October 22, 2014 we have US$26 million per month hedged for the remainder of 2014 at an average USD/CDN floor of 1.1064, ceiling of 1.1500 and conditional ceiling of 1.1212. For 2015, we have US$24 million per month hedged at an average USD/CDN floor of 1.1088, ceiling of 1.1845 and conditional ceiling of 1.1263. Under these contracts, if the monthly foreign exchange rate settles above the ceiling rate the conditional ceiling is used to determine the settlement amount. During the third quarter, we recorded cash gains of $0.6 million and non-cash mark-to-market losses of $8.7 million on these contracts.

ENERPLUS 2014 Q3 REPORT 9

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. During the third quarter and fourth quarter to date we continued to add risk management positions for both crude oil and natural gas. With the decline in crude oil prices we bought back the upside on a portion of our previously swapped crude oil volumes through costless upside participation collars. With respect to natural gas, we entered into additional swap positions for 2015 and 2016 to add more downside protection.

As of October 22, 2014, we have swapped approximately 64% of our forecasted net crude oil production for the remainder of 2014 at an average price of US$95.29/bbl. For the first and second half of 2015, we have swapped approximately 50% and 26%, respectively, of our forecasted net crude oil production at an average price of US$93.58/bbl, and US$93.86/bbl, respectively. In relation to a portion of the volumes swapped we have purchased call options to participate in price upside above US$94.00/bbl and sold put options at an average strike price of US$63.00/bbl, offsetting the call premium. We also have WCS and MSW differential swap positions to manage our exposure to Canadian crude oil differentials. We expect these contracts to protect a significant portion of our funds flow in the near term.

As of October 22, 2014, we have downside protection on approximately 49% and 28% of our forecasted net natural gas production after royalties for the remainder of 2014 and full year 2015, respectively, consisting of a combination of NYMEX swaps, NYMEX collars and AECO swaps.

The following is a summary of our financial contracts in place at October 22, 2014 expressed as a percentage of our anticipated net production volumes:

	WTI Crude Oil (US$/bbl)⁽¹⁾						AECO Natural Gas (CDN$/Mcf)⁽¹⁾		NYMEX Natural Gas (US$/Mcf)⁽¹⁾
		Oct 1, 2014 – Dec 31, 2014		Jan 1, 2015 – Jun 30, 2015		Jul 1, 2015 – Dec 31, 2015		Oct 1, 2014 – Dec 31, 2014		Oct 1, 2014 – Dec 31, 2014		Jan 1, 2015 – Mar 31, 2015		Apr 1, 2015 – Jun 30, 2015		Jul 1, 2015 – Dec 31, 2015		Jan 1, 2016 – Dec 31, 2016

Downside Protection Swaps
Sold Swaps	$	95.29	$	93.58	$	93.86	$	4.25	$	4.14	$	4.25	$	4.25	$	4.16	$	4.03
%		64%		50%		26%		10%		28%		29%		29%		22%		4%
Downside Protection Collars
Purchased Puts		–		–		–		–	$	4.30	$	4.53		–		–		–
%		–		–		–		–		11%		11%		–		–		–
Sold Calls		–		–		–		–	$	5.08	$	5.53		–		–		–
%		–		–		–		–		11%		11%		–		–		–
Upside Participation Collars
Sold Puts		–	$	63.00	$	63.00		–	$	3.23	$	3.25	$	3.25	$	3.25		–
%		–		6%		6%		–		9%		2%		2%		2%		–
Sold Calls		–		–		–		–	$	5.00	$	5.00	$	5.00	$	5.00		–
%		–		–		–		–		9%		2%		2%		2%		–
Purchased Calls		–	$	94.00	$	94.00		–	$	4.17	$	4.29	$	4.29	$	4.29		–
%		–		6%		6%		–		9%		2%		2%		2%		–

(1): Based on weighted average price (before premiums), assumed average annual production of 102,000 – 104,000 BOE/day for 2014 and 2015, less royalties and production taxes of 23% in aggregate.

10 ENERPLUS 2014 Q3 REPORT

ACCOUNTING FOR PRICE RISK MANAGEMENT

		Three months ended September 30,						Nine months ended September 30,
Risk Management Gains/(Losses) ($ millions)			2014			2013			2014			2013

Cash gains/(losses):
	Crude oil	$	(4.2	)	$	(12.9	)	$	(36.2	)	$	9.0
	Natural gas		1.7			2.3			(6.2	)		1.1

Total cash gains/(losses)		$	(2.5	)	$	(10.6	)	$	(42.4	)	$	10.1
Non-cash gains/(losses):
	Change in fair value – crude oil	$	82.9		$	(45.6	)	$	48.7		$	(66.5	)
	Change in fair value – natural gas		10.9			0.5			8.3			4.3

Total non-cash gains/(losses)		$	93.8		$	(45.1	)	$	57.0		$	(62.2	)

Total gains/(losses)		$	91.3		$	(55.7	)	$	14.6		$	(52.1	)

	Three months ended September 30,						Nine months ended September 30,
(Per BOE)		2014			2013			2014			2013

Total cash gains/(losses)	$	(0.26	)	$	(1.30	)	$	(1.52	)	$	0.42
Total non-cash gains/(losses)		9.80			(5.60	)		2.04			(2.58	)

Total gains/(losses)	$	9.54		$	(6.90	)	$	0.52		$	(2.16	)

During the third quarter 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. In comparison, during the third quarter of 2013, we realized cash losses of $12.8 million on our crude oil contracts and cash gains of $2.3 million on our natural gas contracts. The cash losses realized in 2014 and 2013 were a result of crude oil prices rising above our fixed price swap positions, while cash gains were due to natural gas contracts that provided floor protection above market prices.

As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At the end of the third quarter of 2014, the fair value of our crude oil and natural gas contracts represented net gain positions of $33.8 million and $8.6 million, respectively. For the three and nine months ended September 30, 2014 the change in the fair value of our crude oil contracts represented gains of $82.9 million and $48.7 million, respectively, while the change in fair value of our natural gas contracts represented gains of $10.9 million and $8.3 million, respectively.

Revenues

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2014			2013			2014			2013

Oil and natural gas sales	$	456.2		$	441.5		$	1,455.8		$	1,219.8
Royalties		(77.9	)		(76.1	)		(254.8	)		(199.7	)

Oil and natural gas sales, net of royalties	$	378.3		$	365.4		$	1,201.0		$	1,020.1

Oil and natural gas sales were $456.2 million in the third quarter of 2014, an increase of 3% or $14.7 million compared to the same period in 2013. For the nine months ended September 30, 2014, oil and natural gas sales were $1,455.8 million, an increase of 19% or $236.0 million compared to the same period a year ago. The increase in revenues was driven primarily by year over year production growth. Although crude oil and natural gas liquids selling prices were lower during the quarter compared to the same period in 2013, improved pricing in the first half of the year led to an overall improvement in realized prices year to date.

ENERPLUS 2014 Q3 REPORT 11

Royalties and Production Taxes

	Three months ended September 30,				Nine months ended September 30,
($ millions)		2014		2013		2014		2013

Royalties	$	77.9	$	76.1	$	254.8	$	199.7
Production taxes		21.3		20.0		61.1		52.5

Royalties and production taxes	$	99.2	$	96.1	$	315.9	$	252.2

As a % of oil and natural gas sales, net of transportation		22%		22%		22%		21%

	Three months ended September 30,				Nine months ended September 30,
(Per BOE)		2014		2013		2014		2013

Royalties	$	8.14	$	9.43	$	9.12	$	8.27
Production taxes		2.22		2.48		2.19		2.19

Royalties and production taxes	$	10.36	$	11.91	$	11.31	$	10.46

As a % of oil and natural gas sales, net of transportation		22%		22%		22%		21%

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, 2014 royalties and production taxes increased to $99.2 million and $315.9 million, respectively, from $96.1 million and $252.2 million for the same periods in 2013. This upward trend is primarily due to increased production from higher royalty rate U.S. properties. As a percentage of oil and gas sales, net of transportation costs, royalties and production taxes averaged 22% for the three and nine months ended September 30, 2014 compared to 22% and 21%, respectively, for the same periods in 2013.

We continue to expect an average royalty and production tax rate of 23% in 2014.

Operating Expenses

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

Operating Expenses	$	102.1	$	85.5	$	286.7	$	252.3
Per BOE	$	10.67	$	10.60	$	10.27	$	10.46

Operating expenses for the three and nine months ended September 30, 2014 were $102.1 million or $10.67/BOE and $286.7 million or $10.27/BOE, respectively. In comparison, operating costs were $85.5 million or $10.60/BOE and $252.3 million or $10.46/BOE for the same periods in 2013.

The production curtailments at our lower operating cost Marcellus properties negatively impacted operating costs on a per BOE basis during the quarter. Seasonal well servicing and higher repairs and maintenance costs also increased our operating costs in the third quarter.

Based on ongoing production curtailments in the Marcellus in the fourth quarter we have revised our 2014 guidance to $10.25/BOE from $10.10/BOE, consistent with our original guidance for 2014.

Transportation Costs

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

Transportation costs	$	14.7	$	8.8	$	40.9	$	22.3
Per BOE	$	1.53	$	1.09	$	1.46	$	0.92

12 ENERPLUS 2014 Q3 REPORT

Transportation costs for the three and nine months ended September 30, 2014 were $14.7 million or $1.53/BOE and $40.9 million or $1.46/BOE, respectively, compared to $8.8 million or $1.09/BOE and $22.3 million or $0.92/BOE for the same periods in 2013. The increase from the prior year was related to higher U.S. production as well as costs associated with securing U.S. pipeline capacity.

Netbacks

The following tables outline our crude oil and natural gas netbacks for the three and nine months ended September 30, 2014 and 2013. 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 presentation.

	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⁽²⁾	$	80.15		$	3.32		$	46.13
Royalties and production taxes		(20.73	)		(0.40	)		(10.36	)
Cash operating costs		(13.13	)		(1.46	)		(10.67	)

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

	Three months ended September 30, 2013
Netbacks by Property Type		Crude Oil			Natural Gas			Total

Average Daily Production		43,670 BOE/day			264,354 Mcfe/day			87,729 BOE/day

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

Oil and natural gas sales⁽²⁾	$	88.44		$	3.18		$	53.61
Royalties and production taxes		(20.74	)		(0.53	)		(11.91	)
Cash operating costs		(12.26	)		(1.49	)		(10.58	)

Netback before hedging	$	55.44		$	1.16		$	31.12

Cash gains/(losses)		(3.20	)		0.10			(1.30	)

Netback after hedging	$	52.24		$	1.26		$	29.82

Netback before hedging ($ millions)	$	222.7		$	28.5		$	251.2

Netback after hedging ($ millions)	$	209.9		$	30.8		$	240.6

ENERPLUS 2014 Q3 REPORT 13

	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⁽²⁾	$	84.18		$	4.17		$	50.66
Royalties and production taxes		(21.08	)		(0.64	)		(11.31	)
Cash operating costs		(12.78	)		(1.39	)		(10.28	)

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

	Nine months ended September 30, 2013
Netbacks by Property Type		Crude Oil			Natural Gas			Total

Average Daily Production		43,447 BOE/day			269,226 Mcfe/day			88,318 BOE/day

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

Oil and natural gas sales⁽²⁾	$	78.41		$	3.64		$	49.67
Royalties and production taxes		(18.37	)		(0.47	)		(10.46	)
Cash operating costs		(12.25	)		(1.47	)		(10.52	)

Netback before hedging	$	47.79		$	1.70		$	28.69

Cash gains/(losses)		0.76			0.02			0.42

Netback after hedging	$	48.55		$	1.72		$	29.11

Netback before hedging ($ millions)	$	566.8		$	125.0		$	691.8

Netback after hedging ($ millions)	$	575.8		$	126.1		$	701.9

(1): See "Non-GAAP Measures" in this MD&A.
(2): Net of transportation costs.

Our crude oil properties accounted for 75% of our corporate netback before hedging for the year to date compared to 82% for the same period in 2013. Crude oil netbacks per BOE before hedging decreased during the three months ended September 30, 2014 compared to the same period in 2013 primarily due to lower realized crude oil prices. For the nine months ended September 30, 2014 average realized crude oil prices were higher than the same period in 2013 which resulted in higher crude oil netbacks before hedging compared to the previous year. Natural gas netbacks per Mcfe before hedging increased for the three and nine months ended compared to the same period last year primarily due to the increase in realized natural gas prices from 2013.

14 ENERPLUS 2014 Q3 REPORT

General and Administrative ("G&A") Expenses

Total G&A expenses include cash G&A expenses as well as share-based compensation ("SBC") charges related to our long-term incentive plans ("LTI plans") and our stock option plan. SBC charges are dependent on our share price and can fluctuate from period to period.

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2014			2013			2014			2013

Cash:
G&A expense⁽¹⁾	$	18.9		$	20.0		$	58.1		$	63.5
SBC expense/(recovery)		(5.2	)		4.9			12.3			14.1
Non-Cash:
SBC		3.4			1.7			9.9			7.2
SBC – equity swap loss/(gain)		5.8			(1.5	)		(0.1	)		(3.8	)

Total G&A expenses	$	22.9		$	25.1		$	80.2		$	81.0

	Three months ended September 30,						Nine months ended September 30,
(Per BOE)		2014			2013			2014		2013

Cash:
G&A expense⁽¹⁾	$	1.97		$	2.48		$	2.08	$	2.63
SBC expense/(recovery)		(0.54	)		0.60			0.44		0.58
Non-Cash:
SBC		0.36			0.21			0.35		0.30
SBC – equity swap loss/(gain)		0.61			(0.18	)		–		(0.16	)

Total G&A expenses	$	2.40		$	3.11		$	2.87	$	3.35

(1): Excluding SBC.

Cash G&A expenses during the third quarter were $18.9 million or $1.97/BOE compared to $20.0 million or $2.48/BOE in the third quarter of 2013. For the nine months ended September 30, 2014 cash G&A expenses were $58.1 million or $2.08/BOE compared to $63.5 million or $2.63/BOE for the same period in 2013. The decrease during 2014 was partially due to one-time charges recorded in the prior year associated with the departure of personnel, while higher production volumes in 2014 also contributed to a decrease in our reported G&A on a per BOE basis. We are maintaining our cash G&A guidance at $2.30/BOE for the year.

Our share price decreased by 21% during the quarter, reducing our cash SBC expense and resulting in a recovery of $5.2 million or $0.54/BOE compared to a charge of $4.9 million or $0.60/BOE during the third quarter of 2013. For the nine months ended September 30, 2014 cash SBC expense was $12.3 million or $0.44/BOE compared to $14.1 million or $0.58/BOE for the same period in the prior year.

We have hedged a portion of the outstanding cash settled units under our LTI plans at an average price of $14.92/share. As a result of the decrease in our share price we recorded a non-cash mark-to-market loss of $5.8 million for the quarter and a gain of $0.1 million for the nine months ended September 30, 2014.

Based on our September 30, 2014 share price of $21.26 we have revised our 2014 guidance for cash SBC to $0.45/BOE from $0.60/BOE.

Interest Expense

	Three months ended September 30,				Nine months ended September 30,
($ millions)		2014		2013		2014		2013

Interest on senior notes and bank facility	$	14.9	$	14.7	$	45.5	$	43.1
Non-cash interest expense		0.3		0.4		1.4		1.2

Total interest expense	$	15.2	$	15.1	$	46.9	$	44.3

For the three and nine months ended September 30, 2014 we recorded total interest expense of $15.2 million and $46.9 million, respectively, compared to $15.1 million and $44.3 million in the same periods in 2013.

ENERPLUS 2014 Q3 REPORT 15

Interest expense increased marginally for the three and nine months ended September 30, 2014 compared to the same periods in 2013 mainly due to the impact of a weaker Canadian dollar on our U.S. dollar denominated interest payments.

At September 30, 2014, after including our underlying derivatives, approximately 95% of our debt was based on fixed interest rates and 5% on floating interest rates, with weighted average interest rates of 5.28% and 2.92%, respectively. The percentage of fixed rate debt has increased from prior periods as we closed our US$200.0 million senior notes offering on September 3, 2014 and used the proceeds to pay down bank debt.

Foreign Exchange

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2014			2013			2014		2013

Realized loss/(gain)	$	(2.6	)	$	0.1		$	14.0	$	17.7
Unrealized loss/(gain)		33.1			(2.6	)		10.7		(13.7	)

Total foreign exchange loss/(gain)	$	30.5		$	(2.5	)	$	24.7	$	4.0

We recorded a net foreign exchange loss of $30.5 million during the third quarter and a loss of $24.7 million year to date, compared to a net gain of $2.5 million and a net loss of $4.0 million, respectively, during the same periods in 2013.

Realized gains during the quarter resulted from foreign exchange gains on day-to-day transactions denominated in foreign currencies. Unrealized foreign exchange losses related to the translation of our U.S. dollar denominated debt and working capital.

Capital Investment and Dispositions

	Three months ended September 30,						Nine months ended September 30,
($ millions)		2014			2013			2014			2013

Capital spending	$	207.8		$	145.8		$	630.0		$	458.4
Office capital		1.4			1.2			3.0			3.4

Sub-total	$	209.2		$	147.0		$	633.0		$	461.8

Property and land acquisitions	$	4.0		$	15.8		$	17.2		$	71.5
Property dispositions		(68.9	)		(124.5	)		(185.6	)		(197.1	)

Sub-total	$	(64.9	)	$	(108.7	)	$	(168.4	)	$	(125.6	)

Total net capital investment	$	144.3		$	38.3		$	464.6		$	336.2

Capital spending for the third quarter totaled $207.8 million compared to $145.8 million during the same period in 2013. We continue to focus our spending on our core development areas with 64% directed towards crude oil development. Crude oil spending for the quarter included $95.7 million at Fort Berthold and $37.0 million on our Canadian waterflood properties. Natural gas spending included $56.6 million in the Marcellus and $16.1 million on our Deep Basin assets.

During the quarter we had minor property and land acquisitions totaling $4.0 million, of which $2.0 million related to undeveloped land acquisitions in our Deep Basin properties and $2.0 million related to additional land interests around our existing Marcellus acreage. In the third quarter of 2013 we spent $15.8 million which included $6.4 million for additional land interests in the Deep Basin, $7.5 million in Fort Berthold and $1.9 million in the Marcellus.

On September 30, 2014, we divested of $69.0 million of non-core natural gas properties in the Deep Basin area with production of approximately 1,900 BOE/day. During the quarter, we also entered into an agreement to sell additional non-core Canadian natural gas properties with production of approximately 1,200 BOE/day for net proceeds of approximately $22.0 million. This transaction closed in early November. Combined, we expect to realize approximately $30,000 per flowing barrel on these non-core gas divestments.

16 ENERPLUS 2014 Q3 REPORT

Property dispositions during the third quarter of 2013 totaled $124.5 million which included non-core Canadian properties primarily in Saskatchewan and Alberta for proceeds of $89.3 million as well as certain facilities in Fort Berthold for proceeds of $35.2 million.

Our successful non-core divestments have allowed us to increase our capital spending program and redeploy a portion of the proceeds to accelerate our 2015 capital spending programs in Fort Berthold and the Wilrich. As a result, we have increased our capital spending guidance for the year to $830 million from $800 million.

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

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

DDA&A expense	$	159.7	$	163.3	$	440.5	$	470.1
Per BOE	$	16.68	$	20.24	$	15.77	$	19.50

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, 2014 DDA&A decreased to $159.7 million and $440.5 million, respectively, compared to $163.3 million and $470.1 million during the same periods in 2013. The decrease was primarily due to significant reserve additions for the year ended December 31, 2013 that lowered our depletion rate for 2014.

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 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 $286.7 million at September 30, 2014 compared to $291.8 million at December 31, 2013.

Income Taxes

	Three months ended September 30,					Nine months ended September 30,
($ millions)		2014		2013			2014		2013

Current tax expense	$	–	$	5.2		$	11.4	$	7.9
Deferred tax expense/(recovery)		36.9		(6.6	)		74.1		15.6

Total tax expense/(recovery)	$	36.9	$	(1.4	)	$	85.5	$	23.5

For the three and nine months ended September 30, 2014, we recorded a total tax expense of $36.9 million and $85.5 million respectively, compared to a $1.4 million tax recovery and a $23.5 million tax expense in the same periods in 2013. The increase in our total tax expense is due to higher net income in 2014.

Our current tax is comprised mainly of Alternative Minimum Tax ("AMT") payable with respect to our U.S. subsidiary. We expect to recover AMT in future years as an offset to regular U.S. income taxes otherwise payable. Given the decrease in commodity prices and resulting decrease in forecasted net income for the year, a current tax accrual was not needed during the third quarter. Based on current commodity prices and assuming no acquisitions and divestiture activity, we expect to pay U.S. cash taxes of approximately 2% of our U.S. funds flow in 2014, and approximately 3% – 5% from 2015 to 2018. We currently do not expect to pay material cash taxes in Canada until after 2018.

ENERPLUS 2014 Q3 REPORT 17

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

The following table provides a geographical split of key operating and financial results for the three and nine months ended September 30, 2014 and 2013.

		Three months ended September 30, 2014									Three months ended September 30, 2013
(millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes⁽¹⁾
	Crude oil (bbls/day)		16,837			23,495			40,332			17,246			21,637			38,883
	Natural gas liquids (bbls/day)		2,578			1,291			3,869			2,265			720			2,985
	Natural gas (Mcf/day)		154,855			204,152			359,007			174,169			100,995			275,164

	Total average daily production (BOE/day)		45,224			58,811			104,035			48,539			39,190			87,729

Pricing⁽²⁾
	Crude oil (per bbl)	$	82.11		$	89.63		$	86.49		$	94.12		$	98.04		$	96.30
	Natural gas liquids (per bbl)		46.28			42.01			44.85			58.64			22.31			49.88
	Natural gas (per Mcf)		3.82			2.77			3.22			2.62			3.55			2.96
Capital Expenditures
	Capital spending	$	55.2		$	152.6		$	207.8		$	57.0		$	88.8		$	145.8
	Acquisitions		2.0			2.0			3.9			6.4			9.4			15.8
	Dispositions		(68.9	)		0.0			(68.9	)		(89.3	)		(35.2	)		(124.5	)
Netback Before Hedging
	Oil and natural gas sales	$	199.3		$	256.9		$	456.2		$	209.6		$	231.9		$	441.5
	Royalties		(27.1	)		(50.8	)		(77.9	)		(31.6	)		(44.5	)		(76.1	)
	Cash operating expense		(64.7	)		(37.3	)		(102.0	)		(62.2	)		(23.2	)		(85.4	)
	Production taxes		(2.5	)		(18.8	)		(21.3	)		(1.4	)		(18.6	)		(20.0	)
	Transportation expense		(6.2	)		(8.5	)		(14.7	)		(5.5	)		(3.3	)		(8.8	)

	Netback before hedging	$	98.8		$	141.5		$	240.3		$	108.9		$	142.3		$	251.2

Other Expenses
	Commodity derivative instruments loss/(gain)	$	(91.3	)	$	–		$	(91.3	)	$	55.7		$	–		$	55.7
	General and administrative expense		19.8			3.1			22.9			20.7			4.4			25.1
	Current income tax expense/(recovery)		(0.1	)		0.1			–			(0.3	)		5.5			5.2

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

18 ENERPLUS 2014 Q3 REPORT

		Nine months ended September 30, 2014									Nine months ended September 30, 2013
(millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes⁽¹⁾
	Crude oil (bbls/day)		16,867			22,461			39,328			18,253			20,173			38,426
	Natural gas liquids (bbls/day)		2,531			1,060			3,591			2,782			575			3,357
	Natural gas (Mcf/day)		154,306			201,982			356,288			179,503			99,709			279,212

	Total average daily production (BOE/day)		45,116			57,184			102,300			50,952			37,366			88,318

Pricing⁽²⁾
	Crude oil (per bbl)	$	87.05		$	93.81		$	90.91		$	80.02		$	91.50		$	86.05
	Natural gas liquids (per bbl)		57.37			42.60			53.01			56.59			26.77			51.48
	Natural gas (per Mcf)		4.41			3.76			4.04			2.97			3.78			3.26
Capital Expenditures
	Capital spending	$	243.2		$	386.8		$	630.0		$	184.4		$	274.0		$	458.4
	Acquisitions		2.0			15.2			17.2			44.0			27.5			71.5
	Dispositions		(136.6	)		(49.0	)		(185.6	)		(154.5	)		(42.6	)		(197.1	)
Netback Before Hedging
	Oil and natural gas sales	$	645.3		$	810.5		$	1,455.8		$	606.7		$	613.1		$	1,219.8
	Royalties		(96.2	)		(158.6	)		(254.8	)		(82.1	)		(117.6	)		(199.7	)
	Cash operating expense		(189.1	)		(97.8	)		(286.9	)		(193.6	)		(60.0	)		(253.6	)
	Production taxes		(6.4	)		(54.7	)		(61.1	)		(7.8	)		(44.7	)		(52.5	)
	Transportation expense		(17.9	)		(23.0	)		(40.9	)		(17.3	)		(4.9	)		(22.2	)

	Netback before hedging	$	335.7		$	476.4		$	812.1		$	305.9		$	385.9		$	691.8

Other Expenses
	Commodity derivative instruments loss/(gain)	$	(14.6	)	$	–		$	(14.6	)	$	52.1		$	–		$	52.1
	General and administrative expense		65.7			14.5			80.2			69.4			11.6			81.0
	Current income tax expense/(recovery)		(0.5	)		11.9			11.4			(0.3	)		8.2			7.9

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

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

2014
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	$	1,200.9	$	147.4		$	0.73		$	0.70

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	$	1,352.5	$	48.0		$	0.24		$	0.24

2012
Fourth Quarter	$	310.2	$	34.6		$	0.18		$	0.18
Third Quarter		279.3		(88.6	)		(0.45	)		(0.45	)
Second Quarter		274.3		(41.9	)		(0.21	)		(0.21	)
First Quarter		289.5		(174.8	)		(0.92	)		(0.92	)

Total	$	1,153.3	$	(270.7	)	$	(1.38	)	$	(1.38	)

ENERPLUS 2014 Q3 REPORT 19

Oil and gas sales, net of royalties, increased in 2014 compared to 2013 primarily due to increased production and higher realized commodity prices. In the third quarter of 2014 lower realized commodity prices resulted in lower oil and gas sales for the quarter. Throughout 2013 and 2012 oil and gas sales, net of royalties, generally increased with higher production although volatile commodity prices caused some fluctuations.

Net income for 2014 benefited from higher production and generally higher realized prices offset by fluctuating risk management costs and foreign exchange gains and losses. Net income for 2013 and 2012 was impacted by fluctuating risk management costs, asset impairment charges and gains on marketable security divestments.

LIQUIDITY AND CAPITAL RESOURCES

We continued to maintain a strong balance sheet and ample liquidity through the third quarter. At September 30, 2014 we had a conservative trailing 12 month debt to cash flow ratio of 1.3x. On September 3, 2014 we closed a private placement of US$200.0 million of senior unsecured notes, with a twelve year amortizing term, a ten year average life and a fixed interest rate of 3.79%. The proceeds were used to repay our short-term, floating interest rate bank debt, and as a result we had $942.5 million of undrawn capacity on our $1 billion credit facility at quarter end.

Our adjusted payout ratio, calculated as dividends (net of SDP proceeds) plus capital and office spending, divided by funds flow, increased to 122% and 120% for the three and nine months ended September 30, 2014, respectively, compared to 97% and 103% for the same periods in 2013. Although funds flow increased by 8% and 13% for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, we saw a proportionately larger increase in our capital spending program and a decrease in our SDP participation over the same period. Despite the increase in adjusted payout ratio, the health of our balance sheet has been maintained in part due to the success of our non-core asset divestment program.

We continue to hedge a portion of our commodity price risk and expect our risk management program to provide funds flow protection in the near term. At September 30, 2014 we had approximately 64% of our anticipated remaining 2014 crude oil production hedged at a price of $95.29, and approximately 38% of our anticipated 2015 oil production hedged at $93.68.

Total debt net of cash at September 30, 2014 was $1,091.1 million compared to $1,022.3 million at December 31, 2013. Total debt was comprised of $57.5 million of bank indebtedness and $1,035.7 million of senior notes, less $2.1 million in cash. A significant portion of our senior notes are denominated in U.S. dollars and given the weakening Canadian dollar our total reported debt has increased. Our working capital deficiency, excluding cash and current deferred financial and tax assets and credits, increased slightly during the quarter to $252.5 million from $251.2 million in the second quarter. We expect to finance our working capital deficit through funds flow and our bank credit facility.

Our key leverage ratios are detailed below:

(1): Long-term debt is measured net of cash and includes the current portion of the senior notes.
(2): Interest expense excluding non-cash items.

At September 30, 2014 we were in compliance with all covenants under our bank credit facility and 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 and on the EDGAR website at www.sec.gov.

20 ENERPLUS 2014 Q3 REPORT

Dividends

	Three months ended September 30,				Nine months ended September 30,
($ millions, except per share amounts)		2014		2013		2014		2013

Cash dividends	$	51.1	$	42.4	$	143.8	$	128.7
Stock dividend plan		4.3		12.0		21.8		33.5

Total dividends to shareholders	$	55.4	$	54.4	$	165.6	$	162.2

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

During the three and nine months ended September 30, 2014 we maintained our monthly $0.09/share dividend, resulting in dividends to shareholders of $55.4 million ($0.27/share) and $165.6 million ($0.81/share), respectively, compared to $54.5 million ($0.27/share) and $162.2 million ($0.81/share) for the same periods in 2013. For the first nine months of 2014, dividend payments including SDP amounted to 26% of our funds flow of $646.5 million. We continue to monitor our dividend levels with respect to anticipated funds flow, debt levels, capital spending plans and capital market conditions and do not anticipate any changes to our dividend at this time.

Effective September 19, 2014 the Board of Directors elected to suspend the SDP in an effort to eliminate the dilution associated with the issuance of shares through the plan. Effective with the October 2014 dividend, all dividends will be paid in cash on or about the 15th day of the month, approximately five days earlier than previously. All record dates and ex-dividend dates will also be adjusted accordingly with future record dates being on or about the last business day of the previous calendar month.

Commitments

During the third quarter we acquired additional transportation commitments for 11.1 MMcf/day on various pipelines in the Marcellus region. These contracts relate to the additional working interest acquisition at the end of 2013 and have various terms extending out to 2020, 2028 and 2033 and comprise a total commitment of approximately US$54.3 million.

Shareholders' Capital

	Nine months ended September 30,
		2014		2013

Share capital ($ millions)	$	3,115.5	$	3,046.1
Common shares outstanding (thousands)		205,423		201,873
Weighted average shares outstanding – basic (thousands)		204,174		200,002
Weighted average shares outstanding – diluted (thousands)		207,970		200,415

During the third quarter of 2014, a total of 655,000 shares (2013 – 1,605,000) and $12.2 million of additional equity (2013 – $26.9 million) was issued pursuant to the SDP and the stock option plan. For the nine months ended September 30, 2014, a total of 2,665,000 shares (2013 – 3,189,000) and $48.9 million of additional equity (2013 – $48.4 million) was issued pursuant to the SDP and the stock option plan.

At September 30, 2014 we had 205,423,000 shares outstanding (2013 – 201,874,000) and at November 6, 2014 we had 205,434,022 shares outstanding.

ENERPLUS 2014 Q3 REPORT 21

2014 GUIDANCE

A summary of our 2014 guidance is below.

Summary of 2014 Expectations		Target

Average annual production		102,000 – 104,000 BOE/day (from 100,000 – 104,000 BOE/day)
Production mix (volumes)		44,000 BOE/day crude oil and natural gas liquids 58,000-60,000 BOE/day natural gas (from 56,000-60,000 BOE/day)
Capital spending		$830 million (from $800 million)
Average royalty rate (% of gross sales, net of transportation)		23%
Operating costs		$10.25/BOE (from $10.10/BOE)
Cash G&A expenses		$2.30/BOE
Cash share-based compensation expenses		$0.45/BOE (from $0.60/BOE)
U.S. Cash taxes (% of U.S. funds flow)		2% (from 3%-5%)

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 Issuers' 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, 2014, 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, 2014 and ending September 30, 2014 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 2014 and 2015 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged; the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; 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 costs; capital spending levels in 2014 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 U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. 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; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom and production volumes associated therewith.

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; 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; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating and working capital requirements,

22 ENERPLUS 2014 Q3 REPORT

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. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes in commodity prices; changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inaccurate estimation of our oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; a failure to complete planned asset dispositions on the terms anticipated or at all; 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 this MD&A and in our other public filings).

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

ENERPLUS 2014 Q3 REPORT 23

STATEMENTS

Condensed Consolidated Balance Sheets

(CDN$ thousands) unaudited		Note		September 30, 2014			December 31, 2013

Assets
Current assets
	Cash		$	2,104		$	2,990
	Accounts receivable	3		197,576			165,091
	Deferred income tax asset			–			48,476
	Deferred financial assets	15		40,906			9,198
	Other current assets			12,651			7,641

				253,237			233,396

Property, plant and equipment
	Oil and natural gas properties (full cost method)	4		2,528,493			2,420,144
	Other capital assets, net	4		18,862			21,210

	Property, plant and equipment			2,547,355			2,441,354

Goodwill				618,521			609,975
Deferred income tax asset				356,955			364,411
Deferred financial assets		15		32,288			19,274
Marketable securities		5		–			13,389

Total Assets			$	3,808,356		$	3,681,799

Liabilities
Current liabilities
	Accounts payable	6	$	347,268		$	377,157
	Dividends payable			18,488			18,250
	Current portion of long-term debt	7		96,937			48,713
	Deferred income tax liability			6,640			–
	Deferred financial credits	15		–			37,031

				469,333			481,151

Long-term debt		7		996,277			976,585
Asset retirement obligation		8		286,748			291,761

				1,283,025			1,268,346

Total Liabilities				1,752,358			1,749,497

Shareholders' Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: September 30, 2014 – 205 million shares December 31, 2013 – 203 million shares		14		3,115,527			3,061,839
Paid-in capital		14		43,522			38,398
Accumulated deficit				(1,135,401	)		(1,117,238	)
Accumulated other comprehensive income/(loss)				32,350			(50,697	)

				2,055,998			1,932,302

Total Liabilities & Equity			$	3,808,356		$	3,681,799

Contingencies and Commitments		16

See accompanying notes to the Condensed Consolidated Financial Statements

24 ENERPLUS 2014 Q3 REPORT

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

			Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands, except per share amounts) unaudited		Note		2014			2013			2014			2013

Revenues
Oil and natural gas sales, net of royalties		9	$	378,332		$	365,391		$	1,200,997		$	1,020,096
Commodity derivative instruments gain/(loss)		15		91,268			(55,674	)		14,602			(52,107	)

				469,600			309,717			1,215,599			967,989

Expenses
Operating				102,093			85,548			286,683			252,262
Production taxes				21,270			20,004			61,116			52,486
Transportation				14,667			8,830			40,915			22,259
General and administrative		10		22,937			25,114			80,240			80,989
Depletion, depreciation, amortization and accretion				159,658			163,339			440,494			470,088
Interest		11		15,175			15,084			46,876			44,321
Foreign exchange (gain)/loss		12		30,498			(2,509	)		24,742			4,027
Other expense/(income)				(953	)		(548	)		1,599			(264	)

				365,345			314,862			982,665			926,168

Income/(Loss) Before Taxes				104,255			(5,145	)		232,934			41,821
Current income tax expense/(recovery)		13		(28	)		5,235			11,447			7,943
Deferred income tax expense/(recovery)		13		36,853			(6,660	)		74,063			15,528

Net Income/(Loss)			$	67,430		$	(3,720	)	$	147,424		$	18,350

Other Comprehensive Income/(Loss)
Changes due to marketable securities (net of tax)
	Unrealized gain/(loss)			–			2,244			(145	)		5,104
	Realized (gain)/loss reclassified to net income			–			(125	)		2,503			(315	)
Change in cumulative translation adjustment				78,459			(24,307	)		80,689			34,336

Other Comprehensive Income/(Loss)				78,459			(22,188	)		83,047			39,125

Total Comprehensive Income/(Loss)			$	145,889		$	(25,908	)	$	230,471		$	57,475

Net Income/(Loss) per Share
Basic		14	$	0.33		$	(0.02	)	$	0.72		$	0.09
Diluted		14	$	0.32		$	(0.02	)	$	0.71		$	0.09

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2014 Q3 REPORT 25

Condensed Consolidated Statements of Changes
in Shareholders' Equity

Nine months ended September 30, (CDN$ thousands) unaudited			2014			2013

Share Capital
Balance, beginning of year		$	3,061,839		$	2,997,682
Stock Option Plan – cash			27,068			12,723
Share-based compensation – non-cash			4,783			2,222
Stock Dividend Plan			21,837			33,489

Balance, end of period		$	3,115,527		$	3,046,116

Paid-in Capital
Balance, beginning of year		$	38,398		$	32,293
Stock Option Plan – exercised			(4,783	)		(2,222	)
Share-based compensation – expensed			9,907			7,164

Balance, end of period		$	43,522		$	37,235

Accumulated Deficit
Balance, beginning of year		$	(1,117,238	)	$	(948,350	)
Net income			147,424			18,350
Dividends			(165,587	)		(162,199	)

Balance, end of period		$	(1,135,401	)	$	(1,092,199	)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of year		$	(50,697	)	$	(130,385	)
Changes due to marketable securities (net of tax)
	Unrealized gains/(losses)		(145	)		5,104
	Realized (gains)/losses reclassified to net income		2,503			(315	)
Change in cumulative translation adjustment			80,689			34,336

Balance, end of period		$	32,350		$	(91,260	)

Total Shareholders' Equity		$	2,055,998		$	1,899,892

See accompanying notes to the Condensed Consolidated Financial Statements

26 ENERPLUS 2014 Q3 REPORT

Condensed Consolidated Statements of Cash Flows

			Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands) unaudited		Note		2014			2013			2014			2013

Operating Activities
Net income/(loss)			$	67,430		$	(3,720	)	$	147,424		$	18,350
Non-cash items add/(deduct):
	Depletion, depreciation, amortization and accretion			159,658			163,339			440,494			470,088
	Changes in fair value of derivative instruments	15		(88,689	)		48,950			(81,750	)		35,061
	Deferred income tax expense/(recovery)	13		36,853			(6,660	)		74,063			15,528
	Foreign exchange (gain)/loss on debt and working capital	12		33,863			(7,446	)		35,798			9,092
	Share-based compensation	14		3,413			1,686			9,907			7,164
	Amortization of debt issue costs			251			188			744			565
Derivative settlement on senior notes				–			–			17,024			18,011
Asset disposition (gain)/loss				–			(150	)		2,798			(367	)
Asset retirement obligation expenditures		8		(3,299	)		(3,701	)		(11,831	)		(10,036	)
Changes in non-cash operating working capital		17		(10,435	)		25,684			(66,710	)		11,372

Cash flow from operating activities				199,045			218,170			567,961			574,828

Financing Activities
Proceeds from the issuance of shares				7,875			12,694			27,068			12,723
Cash dividends		14		(51,088	)		(42,411	)		(143,750	)		(128,710	)
Change in bank debt				(236,013	)		(144,858	)		(159,303	)		(74,769	)
Issuance (repayment) of senior notes				217,460			–			179,562			(35,655	)
Derivative settlement on senior notes				–			–			(17,024	)		(18,011	)
Changes in non-cash financing working capital				34			137			238			288

Cash flow from financing activities				(61,732	)		(174,438	)		(113,209	)		(244,134	)

Investing Activities
Capital expenditures				(209,197	)		(146,997	)		(633,013	)		(461,838	)
Property and land acquisitions				(3,986	)		(15,792	)		(17,186	)		(71,451	)
Property dispositions				68,931			124,462			185,631			197,086
Sale of marketable securities		5		–			599			13,300			2,482
Changes in non-cash investing working capital				5,116			(145	)		(5,689	)		20,590

Cash flow from investing activities				(139,136	)		(37,873	)		(456,957	)		(313,131	)

Effect of exchange rate changes on cash				1,929			1,696			1,319			(4,452	)

Change in cash				106			7,555			(886	)		13,111
Cash, beginning of period				1,998			10,756			2,990			5,200

Cash, end of period			$	2,104		$	18,311		$	2,104		$	18,311

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2014 Q3 REPORT 27

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 6, 2014.

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") as at September 30, 2014 and for the three and nine months ended September 30, 2014, and the 2013 comparative periods. These interim Consolidated Financial Statements do not include all the necessary annual disclosures as prescribed under U.S. GAAP and should be read in conjunction with Enerplus' audited Consolidated Financial Statements as of December 31, 2013. 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, 2013.

Recent Accounting Pronouncements

Enerplus will adopt the following Accounting Standards Updates ("ASU") issued by the Financial Accounting Standards Board, which have been issued but are not yet effective. The adoption of these standards is not expected to have a material impact on Enerplus' financial statements.

•: ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity – effective January 1, 2015
•: ASU 2014-09, Revenue from Contracts with Customers – effective January 1, 2017
•: ASU 2014-12, Compensation – Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period – effective January 1, 2016

3) ACCOUNTS RECEIVABLE

($ thousands)		September 30, 2014			December 31, 2013

Accrued receivables	$	140,394		$	122,482
Accounts receivable – trade		43,613			36,034
Current income tax receivable		16,424			9,371
Allowance for doubtful accounts		(2,855	)		(2,796	)

Total accounts receivable	$	197,576		$	165,091

28 ENERPLUS 2014 Q3 REPORT

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

As at September 30, 2014 ($ thousands)		Cost		Accumulated Depletion and Depreciation		Net Book Value

Oil and natural gas properties	$	12,152,423	$	9,623,930	$	2,528,493
Other capital assets		93,474		74,612		18,862

Total PP&E	$	12,245,897	$	9,698,542	$	2,547,355

As at December 31, 2013 ($ thousands)		Cost		Accumulated Depletion and Depreciation		Net Book Value

Oil and natural gas properties	$	11,481,207	$	9,061,063	$	2,420,144
Other capital assets		89,818		68,608		21,210

Total PP&E	$	11,571,025	$	9,129,671	$	2,441,354

5) MARKETABLE SECURITIES

During the nine months ended September 30, 2014 Enerplus sold the balance of its publicly listed investments for proceeds of $13.3 million recognizing a loss of $2.8 million. In connection with these sales, realized losses of $2.5 million net of tax ($2.8 million before tax) were reclassified from accumulated other comprehensive income to net income.

6) ACCOUNTS PAYABLE

($ thousands)		September 30, 2014		December 31, 2013

Accrued payables	$	266,120	$	262,117
Accounts payable – trade		81,148		115,040

Total accounts payable	$	347,268	$	377,157

7) DEBT

($ thousands)			September 30, 2014		December 31, 2013

Current:
	Senior notes	$	96,937	$	48,713

		$	96,937	$	48,713

Long term:
	Bank credit facility	$	57,532	$	214,394
	Senior notes		938,745		762,191

		$	996,277	$	976,585

Total debt		$	1,093,214	$	1,025,298

On September 3, 2014 Enerplus closed a private placement of senior unsecured notes raising gross proceeds of US$200,000,000. The notes rank equally with the bank credit facility and other outstanding senior notes. The notes have a twelve year amortizing term and a ten year average life with a fixed coupon rate of 3.79%.

ENERPLUS 2014 Q3 REPORT 29

8) ASSET RETIREMENT OBLIGATION

Enerplus has estimated the present value of its asset retirement obligation to be $286.7 million at September 30, 2014 compared to $291.8 million at December 31, 2013, based on a total undiscounted liability of $707.2 million and $720.6 million, respectively. The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.92% at September 30, 2014 (December 31, 2013 – 5.96%).

($ thousands)		Nine months ended September 30, 2014			Year ended December 31, 2013

Balance, beginning of year	$	291,761		$	256,102
Change in estimates		(1,725	)		44,217
Property acquisition and development activity		1,372			1,454
Dispositions		(3,990	)		(8,362	)
Settlements		(11,831	)		(16,606	)
Accretion Expense		11,161			14,956

Balance, end of period	$	286,748		$	291,761

9) OIL AND NATURAL GAS SALES

		Three months ended September 30,						Nine months ended September 30,
($ thousands)			2014			2013			2014			2013

	Oil and natural gas sales	$	456,215		$	441,503		$	1,455,790		$	1,219,755
	Royalties⁽¹⁾		(77,883	)		(76,112	)		(254,793	)		(199,659	)

Oil and natural gas sales, net of royalties		$	378,332		$	365,391		$	1,200,997		$	1,020,096

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

10) GENERAL AND ADMINISTRATIVE EXPENSE

	Three months ended September 30,				Nine months ended September 30,
($ thousands)		2014		2013		2014		2013

General and administrative expense	$	18,854	$	20,031	$	58,055	$	63,514
Share-based compensation expense⁽¹⁾		4,083		5,083		22,185		17,475

General and administrative expense	$	22,937	$	25,114	$	80,240	$	80,989

(1): Share-based compensation relates to the cash and equity-settled Long-term Incentive Plans and the Stock Option Plan. Refer to Note 14(c) for further discussion.

11) INTEREST EXPENSE

		Three months ended September 30,					Nine months ended September 30,
($ thousands)			2014		2013			2014		2013

Realized: Interest on bank debt and senior notes		$	14,924	$	14,665		$	45,552	$	43,141
Unrealized:
	Cross currency interest rate swap (gain)/loss		–		273			580		1,093
	Interest rate swap (gain)/loss		–		(42	)		–		(478	)
	Amortization of debt issue costs		251		188			744		565

Interest expense		$	15,175	$	15,084		$	46,876	$	44,321

30 ENERPLUS 2014 Q3 REPORT

12) FOREIGN EXCHANGE

		Three months ended September 30,						Nine months ended September 30,
($ thousands)			2014			2013			2014			2013

Realized:
	Foreign exchange (gain)/loss	$	(2,607	)	$	59		$	14,069		$	17,658
Unrealized:
	Translation of U.S. dollar debt and working capital (gain)/loss		33,863			(7,446	)		35,798			9,092
	Cross currency interest rate swap (gain)/loss		–			939			(16,130	)		(19,043	)
	Foreign exchange derivative (gain)/loss		(758	)		3,939			(8,995	)		(3,680	)

Foreign exchange (gain)/loss		$	30,498		$	(2,509	)	$	24,742		$	4,027

13) INCOME TAXES

		Three months ended September 30,						Nine months ended September 30,
($ thousands)			2014			2013			2014			2013

Current tax expense/(recovery)
	Canada	$	(79	)	$	(339	)	$	(453	)	$	(258	)
	U.S.		51			5,574			11,900			8,201

Current tax expense/(recovery)			(28	)		5,235			11,447			7,943

Deferred tax expense/(recovery)
	Canada	$	24,530		$	(17,561	)	$	19,212		$	(20,073	)
	U.S.		12,323			10,901			54,851			35,601

Deferred tax expense/(recovery)		$	36,853		$	(6,660	)	$	74,063		$	15,528

Income tax expense/(recovery)		$	36,825		$	(1,425	)	$	85,510		$	23,471

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

14) SHAREHOLDERS' EQUITY

a) Share Capital

		Nine months ended September 30,			Year ended December 31,

		2014			2013

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

Balance, beginning of year		202,758	$	3,061,839	198,684	$	2,997,682
Issued for cash:
	Stock Option Plan	1,635		27,068	1,042		14,838
Non-cash:
	Stock Option Plan	–		4,783	–		3,108
	Stock Dividend Plan	1,030		21,837	3,032		46,211

Balance, end of period		205,423	$	3,115,527	202,758	$	3,061,839

ENERPLUS 2014 Q3 REPORT 31

b) Dividends

	Three months ended September 30,				Nine months ended September 30,
($ thousands)		2014		2013		2014		2013

Cash dividends	$	51,088	$	42,411	$	143,750	$	128,710
Stock dividends		4,350		11,994		21,837		33,489

Dividends to shareholders	$	55,438	$	54,405	$	165,587	$	162,199

c) Share-Based Compensation ("SBC")

The following table summarizes Enerplus' SBC 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)			2014			2013			2014			2013

Cash:
	Long-term incentive plans expense/(recovery)	$	(5,174	)	$	4,869		$	12,338		$	14,074
Non-Cash:
	Long-term incentive plans expense		2,815			–			6,506			–
	Stock option plan expense		598			1,686			3,401			7,164
	Equity swap (gain)/loss		5,844			(1,472	)		(60	)		(3,763	)

Share-based compensation expense		$	4,083		$	5,083		$	22,185		$	17,475

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

In 2014, the Performance Share Unit and Restricted Share Unit 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 Performance Share Unit ("PSU"), Restricted Share Unit ("RSU") and Director Share Unit ("DSU") activity for the nine months ended September 30, 2014:

For the nine months ended September 30, 2014 (thousands of units)		PSU		RSU		DSU	Total

Balance, beginning of year		650		821		99	1,570
Granted		550		832		47	1,429
Vested		–		(375	)	–	(375	)
Forfeited		(30	)	(93	)	–	(123	)

Balance, end of period		1,170		1,185		146	2,501

End of period balances, by grant settlement type:
	Cash-settled units	630		409		146	1,185
	Equity-settled units	540		776		–	1,316

Balance, end of period		1,170		1,185		146	2,501

32 ENERPLUS 2014 Q3 REPORT

Cash-settled LTI Plans

For the three months ended September 30, 2014 the Company recorded a recovery for cash SBC expense of $5.2 million and for the nine months ended September 30, 2014 recorded a charge of $12.3 million (September 30, 2013 – charges of $4.9 million and $14.1 million). For the three and nine months ended September 30, 2014, the Company made cash payments of $2.0 million and $13.8 million, respectively, related to its cash-settled plans (September 30, 2013 – $4.2 million and $11.1 million).

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

At September 30, 2014 ($ thousands, except for years)		PSU⁽¹⁾		RSU		DSU		Total

Cumulative recognized SBC expense	$	19,412	$	7,450	$	3,380	$	30,242
Unrecognized SBC expense		6,910		2,280		–		9,190

Intrinsic value	$	26,322	$	9,730	$	3,380	$	39,432

Weighted-average remaining contractual term (years)		0.8		0.8		–

(1): Includes estimated performance multipliers.

Equity-settled LTI Plans

Equity-settled LTI awards are settled through the issuance of treasury shares and the related SBC expense is recorded as a non-cash amount on the Consolidated Statements of Income/(Loss), with an offset recorded to Paid-in Capital. On settlement, the amount previously recorded to Paid-in Capital is reclassified to Share Capital.

For the three and nine months ended September 30, 2014 the Company recorded non-cash SBC expense of $2.8 million and $6.5 million, respectively. No non-cash amounts were recognized for the three and nine months ended September 30, 2013 with respect to equity-settled grants.

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

At September 30, 2014 ($ thousands, except for years)		PSU⁽¹⁾		RSU		Total

Cumulative recognized SBC expense	$	1,592	$	4,914	$	6,506
Unrecognized SBC expense		6,252		8,561		14,813

	$	7,844	$	13,475	$	21,319

Weighted-average remaining contractual term (years)		2.3		1.6

(1): Includes estimated performance multipliers.

ENERPLUS 2014 Q3 REPORT 33

(ii) Stock Option Plan

The Company did not grant any stock options during the nine months ended September 30, 2014. Activity for the respective reporting periods is as follows:

		Nine months ended September 30, 2014

		Number of Options (thousands)			Weighted Average Exercise Price

Options outstanding
Beginning of year		13,414		$	18.65
	Granted	–			–
	Exercised	(1,635	)		16.56
	Forfeited	(555	)		19.49
	Expired	–			–

Options outstanding, end of period		11,224		$	18.91

Options exercisable at the end of period		6,247		$	21.48

At September 30, 2014, 6,247,000 options were exercisable at a weighted average reduced exercise price of $21.48 with a weighted average remaining contractual term of 4.0 years, giving an intrinsic value of $17.4 million (September 30, 2013 – $2.6 million). The intrinsic value of options exercised during the three and nine months ended September 30, 2014 was $4.3 million and $12.4 million, respectively (September 30, 2013 – $2.2 million and $2.2 million).

At September 30, 2014 the unrecognized SBC expense related to non-vested options was $1.8 million (September 30, 2013 – $6.3 million). The expense is expected to be fully recognized over a weighted-average period of 0.9 years.

d) Paid-in Capital

The following table summarizes the paid-in capital activity for the nine months ended September 30, 2014 and the year ended December 31, 2013:

($ thousands)		Nine months ended September 30, 2014			Year ended December 31, 2013

Balance, beginning of year	$	38,398		$	32,293
Stock Option Plan – exercised		(4,783	)		(3,108	)
Share-based compensation – non-cash		9,907			9,213

Balance, end of period	$	43,522		$	38,398

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)			2014		2013			2014		2013

Net income/(loss)		$	67,430	$	(3,720	)	$	147,424	$	18,350
Weighted average shares outstanding – Basic			205,164		201,117			204,174		200,002
Dilutive impact of share-based compensation⁽¹⁾			3,933		–			3,796		413

Weighted average shares outstanding – Diluted			209,097		201,117			207,970		200,415

Net income/(loss) per share
	Basic		0.33		(0.02	)		0.72		0.09
	Diluted		0.32		(0.02	)		0.71		0.09

(1): For the three months ended September 30, 2013, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.

34 ENERPLUS 2014 Q3 REPORT

15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At September 30, 2014, 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, 2014 senior notes included in long-term debt had a carrying value of $1,035.7 million and a fair value of $1,118.7 million (December 31, 2013 – $810.9 million and $837.8 million, respectively).

Enerplus' derivative financial instruments are classified as Level 2. A Level 2 classification is appropriate where observable inputs other than quoted market prices are used in the fair value determination.

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

b) Derivative Financial Instruments

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

The following table summarizes the change in fair value for the three and nine months ended September 30, 2014 and 2013:

			Three months ended September 30,						Nine months ended September 30,
Gain/(Loss) ($ thousands)				2014			2013			2014			2013		Income Statement Presentation

Interest Rate Swaps			$	–		$	42		$	–		$	478		Interest
Cross Currency Interest Rate Swap:
	Interest			–			(273	)		(580	)		(1,093	)	Interest
	Foreign Exchange			–			(939	)		16,130			19,043		Foreign Exchange
Foreign Exchange Derivatives				758			(3,939	)		8,995			3,680		Foreign Exchange
Electricity Swaps				22			(156	)		204			1,314		Operating
Equity Swaps				(5,844	)		1,472			60			3,763		General and Administrative
Commodity Derivative Instruments:
		Oil		82,874			(45,609	)		48,671			(66,501	)	Commodity derivative
		Gas		10,879			452			8,270			4,255		instruments Gain/(loss)

Total			$	88,689		$	(48,950	)	$	81,750		$	(35,061	)

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

	Three months ended September 30,						Nine months ended September 30,
($ thousands)		2014			2013			2014			2013

Change in fair value gain/(loss)	$	93,753		$	(45,157	)	$	56,941		$	(62,246	)
Net realized cash gain/(loss)		(2,485	)		(10,517	)		(42,339	)		10,139

Commodity derivative instruments gain/(loss)	$	91,268		$	(55,674	)	$	14,602		$	(52,107	)

ENERPLUS 2014 Q3 REPORT 35

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

		September 30, 2014						December 31, 2013
		Assets				Liabilities		Assets				Liabilities
($ thousands)			Current		Long-term		Current		Current		Long-term		Current

Cross Currency Interest Rate Swap		$	–	$	–	$	–	$	–	$	–	$	15,548
Foreign Exchange Derivatives			758		23,937		–		564		15,135		–
Electricity Swaps			113		–		–		–		–		95
Equity Swaps			4,196		1,726		–		1,723		4,139		–
Commodity Derivative Instruments:
	Oil		28,251		5,588		–		4,138		–		18,970
	Gas		7,588		1,037		–		2,773		–		2,418

Total		$	40,906	$	32,288	$	–	$	9,198	$	19,274	$	37,031

c) Risk Management

(i) Market Risk

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

(ii) 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 Enerplus' price risk management positions at October 22, 2014:

Crude Oil Instruments:

Instrument Type	bbls/day	US$/bbl⁽¹⁾

Oct 1, 2014 – Oct 31, 2014
WTI Swap	20,000	95.29
WCS Differential Swap	4,500	-20.76
Brent – WTI Ratio Spread (% of Brent Price)	4,000	92.72%
Nov 1, 2014 – Dec 31, 2014
WTI Swap	20,000	95.29
WCS Differential Swap	4,000	-21.00
MSW Differential Swap	1,000	-5.90
Brent – WTI Ratio Spread (% of Brent Price)	4,000	92.72%
Jan 1, 2015 – Jun 30, 2015
WTI Swap	15,500	93.58
WCS Differential Swap	3,000	-18.62
WTI Purchased Call	2,000	94.00
WTI Sold Put	2,000	63.00
Jul 1, 2015 – Dec 31, 2015
WTI Swap	8,000	93.86
WCS Differential Swap	2,000	-18.23
WTI Purchased Call	2,000	94.00
WTI Sold Put	2,000	63.00

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

36 ENERPLUS 2014 Q3 REPORT

Natural Gas Instruments:

Instrument Type	MMcf/day	CDN$/Mcf	US$/Mcf

Oct 1, 2014 – Dec 31, 2014
AECO Swap	28.4	4.25
Oct 1, 2014 – Dec 31, 2014
NYMEX Swap	75.0		4.14
NYMEX Collar – Purchased Put	30.0		4.30
NYMEX Collar – Sold Call	30.0		5.08
NYMEX Purchased Call	25.0		4.17
NYMEX Sold Put	25.0		3.23
NYMEX Sold Call	25.0		5.00
Jan 1, 2015 – Mar 31, 2015
NYMEX Swap	80.0		4.25
NYMEX Collar – Purchased Put	30.0		4.53
NYMEX Collar – Sold Call	30.0		5.53
NYMEX Purchased Call	5.0		4.29
NYMEX Sold Put	5.0		3.25
NYMEX Sold Call	5.0		5.00
Apr 1, 2015 – Jun 30, 2015
NYMEX Swap	80.0		4.25
NYMEX Purchased Call	5.0		4.29
NYMEX Sold Put	5.0		3.25
NYMEX Sold Call	5.0		5.00
Jul 1, 2015 – Dec 31, 2015
NYMEX Swap	60.0		4.16
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 Swap	10.0		4.03

Electricity Instruments:

Instrument Type	MWh	CDN$/MWh

Oct 1, 2014 – Dec 31, 2014
AESO Power Swap	16.0	53.33
Jan 1, 2015 – Dec 31, 2015
AESO Power Swap	16.0	50.80
Jan 1, 2016 – Dec 31, 2016
AESO Power Swap	6.0	50.25

ENERPLUS 2014 Q3 REPORT 37

Physical Contracts:

Instrument Type	MMcf/day	US$/Mcf

Oct 1, 2014 – Oct 31, 2014
AECO-NYMEX Basis	60.0	(0.61	)
Nov 1, 2014 – Oct 31, 2015
AECO-NYMEX Basis	50.0	(0.66	)
Nov 1, 2015 – Oct 31, 2016
AECO-NYMEX Basis	60.0	(0.67	)
Nov 1, 2016 – Oct 31, 2017
AECO-NYMEX Basis	70.0	(0.64	)
Nov 1, 2017 – Oct 31, 2018
AECO-NYMEX Basis	70.0	(0.64	)

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 through the derivative instruments detailed below.

Foreign Exchange Derivatives:

During 2014, Enerplus entered into foreign exchange collars to hedge a portion of its foreign exchange exposure on U.S. dollar denominated oil and gas sales. The following contracts are outstanding at October 22, 2014:

Instrument Type⁽¹⁾	Monthly Notional Amount (US$ millions)	Floor	Ceiling	Conditional Ceiling⁽²⁾

Oct 1, 2014 – Dec 31, 2014	26.0	1.1064	1.1500	1.1212
Jan 1, 2015 – Dec 31, 2015	24.0	1.1088	1.1845	1.1263

(1): Transactions with a common term have been aggregated and presented at average USD/CDN foreign exchange rates.
(2): If the USD/CDN average monthly rate settles above the ceiling rate the settlement amount is determined based on the conditional ceiling.

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. At September 30, 2014, following the third settlement, Enerplus had US$21.6 million of remaining notional debt swapped. These foreign exchange swaps mature between October 2014 and October 2015 in conjunction with the remaining principal repayments on the US$54.0 million senior notes.

During 2011 Enerplus entered into foreign exchange swaps on US$175.0 million of notional debt at approximately par. These foreign exchange swaps mature between June 2017 and June 2021 in conjunction with the principal repayments on the US$225.0 million senior notes.

Interest Rate Risk:

At September 30, 2014, approximately 95% of Enerplus' debt was based on fixed interest rates and 5% was based on floating interest rates. The percentage of fixed interest rate debt has increased from prior periods due to the closing of US$200 million in additional senior notes at a fixed rate 3.79% rate of interest, with the proceeds being used to pay down floating interest rate bank debt. At September 30, 2014 Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its cash settled long-term incentive plans detailed in Note 14.

Enerplus has entered into various equity swaps maturing between 2014 and 2016 and has effectively fixed the future settlement cost on 950,000 shares at a weighted average price of $14.92 per share.

38 ENERPLUS 2014 Q3 REPORT

(iii) 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, 2014 approximately 70% of Enerplus' marketing receivables were with companies considered investment grade.

At September 30, 2014 approximately $4.7 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 off 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 uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus' allowance for doubtful accounts balance at September 30, 2014 was $2.9 million (December 31, 2013 – $2.8 million).

(iv) 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.

16) CONTINGENCIES AND COMMITMENTS

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 interim 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.

The Company has entered into an additional transportation commitment for various pipelines in the Marcellus region. These contracts have varied terms, extend out as far as 2033, and comprise a total commitment of approximately US$54.3 million.

ENERPLUS 2014 Q3 REPORT 39

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

	Three months ended September 30,						Nine months ended September 30,
($ thousands)		2014			2013			2014			2013

Accounts receivable	$	6,858		$	17,522		$	(13,019	)	$	2,325
Other current assets		(5,754	)		(1,755	)		(5,210	)		(2,944	)
Accounts payable		(11,539	)		9,917			(48,481	)		11,991

	$	(10,435	)	$	25,684		$	(66,710	)	$	11,372

b) Other

	Three months ended September 30,					Nine months ended September 30,
($ thousands)		2014			2013		2014		2013

Income taxes paid/(received)	$	(254	)	$	3,487	$	18,133	$	(1,403	)
Interest paid	$	4,138		$	2,630	$	32,826	$	31,851

40 ENERPLUS 2014 Q3 REPORT

BOARD OF DIRECTORS

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

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

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

Edwin V. Dodge⁽⁹⁾⁽¹¹⁾
Corporate Director
Vancouver, British Columbia

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

Hilary A. Foulkes^(5)(11)
Corporate Director
Calgary, Alberta

James B. Fraser^(7)(11)
Corporate Director
Polson, Montana

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

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

Douglas R. Martin
Corporate Director
Calgary, Alberta

Donald J. Nelson⁽³⁾⁽⁹⁾
President
Fairway Resources, Inc.
Calgary, Alberta

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

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

OFFICERS

ENERPLUS CORPORATION

Ian C. Dundas
President & Chief Executive Officer

Ray J. Daniels
Senior Vice President, Operations

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

Robert J. Waters
Senior Vice President & Chief Financial Officer

Jo-Anne M. Caza
Vice President, Corporate & Investor Relations

Jodine J. Jenson Labrie
Vice President, Finance

Robert A. Kehrig
Vice President, Business Development and New Plays

H. Gordon Love
Vice President, Technical & Operations Services

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

Edward L. McLaughlin
President, U.S. Operations

Lisa M. Ower
Vice President, Human Resources

Christopher M. Stephens
Vice President, Canadian Assets

P. Scott Walsh
Vice President, Information & Corporate Services

Kenneth W. Young
Vice President, Land

Michael R. Politeski
Treasurer & Corporate Controller

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

ENERPLUS 2014 Q3 REPORT 41

CORPORATE INFORMATION

OPERATING COMPANIES OWNED BY ENERPLUS
CORPORATION
Enerplus Resources (USA) Corporation

LEGAL COUNSEL
Blake, Cassels & Graydon LLP
Calgary, Alberta

AUDITORS
Deloitte LLP
Calgary, Alberta

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

U.S. CO-TRANSFER AGENT
Computershare Trust Company, N.A.
Golden, Colorado

INDEPENDENT RESERVE ENGINEERS
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
Netherland, Sewell & Associates, Inc.
Dallas, Texas

STOCK EXCHANGE LISTINGS AND TRADING
SYMBOLS
Toronto Stock Exchange: ERF
New York Stock Exchange: ERF

U.S.OFFICE
950 17^th Street, Suite 2200
Denver, Colorado 80202
Telephone: 720.279.5500
Fax: 720.279.5550

42 ENERPLUS 2014 Q3 REPORT

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

ENERPLUS 2014 Q3 REPORT 43

QuickLinks

Exhibit 99.1

Financial Leverage and Coverage

September 30, 2014

December 31, 2013

Long-term debt to funds flow (trailing 12-month)⁽¹⁾

Funds flow to interest expense (trailing 12-month)⁽²⁾

Long-term debt to long-term debt plus equity⁽¹⁾