EX-99.1 2 a2221045zex-99_1.htm EXHIBIT 99.1
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Exhibit 99.1

Selected Financial Results

SELECTED FINANCIAL RESULTS	Three months ended June 30,						Six months ended June 30,
		2014			2013			2014			2013

Financial (000's)
Funds Flow	$	213,211		$	204,706		$	433,723		$	377,305
Cash and Stock Dividends		55,214			54,009			110,149			107,794
Net Income		39,957			38,467			79,994			22,070
Debt Outstanding – net of cash		1,067,590			1,133,048			1,067,590			1,133,048
Capital Spending		204,427			139,644			422,190			312,591
Property and Land Acquisitions		3,231			51,692			13,200			55,659
Property Dispositions		(525	)		71,293			116,700			72,624
Debt to Trailing 12-Month Funds Flow		1.3x			1.6x			1.3x			1.6x
Financial per Weighted Average Shares Outstanding
Funds Flow	$	1.04		$	1.02		$	2.13		$	1.89
Net Income (Basic)		0.20			0.19			0.39			0.11
Weighted Average Number of Shares Outstanding (000's)		204,158			199,825			203,671			199,430
Selected Financial Results per BOE⁽¹⁾⁽²⁾
Oil & Natural Gas Sales⁽³⁾	$	51.93		$	48.65		$	53.03		$	47.68
Royalties and Production Taxes		(11.58	)		(9.93	)		(11.81	)		(9.73	)
Commodity Derivative Instruments		(2.60	)		1.11			(2.17	)		1.29
Operating Costs		(10.12	)		(10.55	)		(10.07	)		(10.48	)
General and Administrative		(1.97	)		(2.29	)		(2.14	)		(2.71	)
Share-Based Compensation		(1.12	)		(0.45	)		(0.95	)		(0.57	)
Interest, Foreign Exchange and Other Expenses		(1.61	)		(1.38	)		(1.63	)		(1.78	)
Taxes		(0.40	)		(0.18	)		(0.63	)		(0.18	)

Funds Flow	$	22.53		$	24.98		$	23.63		$	23.52

SELECTED OPERATING RESULTS	Three months ended June 30,				Six months ended June 30,
		2014		2013		2014		2013

Average Daily Production⁽²⁾
Crude oil (bbls/day)		39,863		38,066		38,817		38,193
NGLs (bbls/day)		3,636		3,497		3,450		3,546
Natural gas (Mcf/day)		362,929		290,841		354,906		281,275
Total (BOE/day)		103,987		90,037		101,418		88,618
% Natural Gas		58%		54%		58%		53%
Average Selling Price⁽²⁾⁽³⁾
Crude oil (per bbl)	$	94.90	$	82.95	$	93.25	$	80.74
NGLs (per bbl)		49.98		45.64		57.66		52.16
Natural gas (per Mcf)		4.02		3.70		4.46		3.41
Net Wells drilled		14		10		44		35

(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 Q2 REPORT 1

	Three months ended June 30,				Six months ended June 30,
Average Benchmark Pricing		2014		2013		2014		2013

WTI crude oil (US$/bbl)	$	102.99	$	94.22	$	100.84	$	94.30
AECO – monthly index (CDN$/Mcf)		4.68		3.59		4.72		3.34
AECO – daily index (CDN$/Mcf)		4.69		3.53		5.20		3.37
NYMEX – last day (US$/Mcf)		4.67		4.09		4.80		3.71
USD/CDN exchange rate		1.09		1.02		1.10		1.02

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

High	$	26.92	$	25.24
Low	$	21.54	$	19.58
Close	$	26.89	$	25.18

*: 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

April	$	0.09	$	0.08
May	$	0.09	$	0.08
June	$	0.09	$	0.08

Second Quarter Total	$	0.27	$	0.24

Total Year-to-Date	$	0.54	$	0.48

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

2 ENERPLUS 2014 Q2 REPORT

PRESIDENT'S MESSAGE

I am pleased to report that Enerplus delivered another quarter of strong operational and financial performance. We achieved record production of 104,000 BOE per day which is the highest level in our 28 year history. We grew production in each of our four core areas. In particular, our North Dakota production grew by 14% from the first quarter of 2014.

Daily production was up 5% quarter over quarter, and 15% higher than the same period one year ago. Liquids production grew by 6% quarter over quarter averaging 43,500 barrels per day driven by the significant growth in light oil from North Dakota. The Marcellus also continued to outperform increasing our total natural gas volumes quarter over quarter.

As a result of the continued operational outperformance, we are increasing our annual average production guidance by 4,000 BOE per day. We now expect to produce between 100,000 BOE per day and 104,000 BOE per day in 2014. We continue to expect to grow our liquids volumes throughout the year and are maintaining our guidance of 44,000 barrels per day in 2014. Natural gas production is also expected to grow ahead of our expectations due to the performance of the Marcellus. It also assumes the sale of 2,500 to 3,500 BOE per day of gas weighted production from non-core properties in Canada that we expect to close in the fourth quarter.

Our capital spending is on track year-to-date. With the strength of our balance sheet and the anticipated proceeds from our non-core divestments we are evaluating opportunities to modestly increase spending in our core areas. At this time, we are maintaining our capital spending guidance at $800 million but plan to review spending levels in the third quarter. We also expect to see an improvement in operating costs and cash general and administrative costs. We are now forecasting operating costs of $10.10 per BOE, down from $10.25 per BOE and cash general and administrative costs of $2.30 per BOE down from our previous guidance of $2.45 per BOE.

During the quarter, the largest share of our capital spending continued to be allocated to Fort Berthold, where we directed almost half of our $204 million investment. Our development activities in this area have significantly increased the value of this asset. As announced on June 18, 2014, our estimate of economic contingent resources has increased by 250% to 136 million BOE. In addition, our drilling inventory increased by 125% and we now estimate approximately 330 net drilling locations, representing 16 years of future drilling at our current two-rig pace. This presentation is available on our website.

Funds flow in the quarter grew by 4% compared to the same period in 2013. Compared to last quarter, our funds flow modestly declined due to a 20% drop in realized natural gas prices. This is despite the growth in production and higher crude oil prices in the quarter. Both AECO and NYMEX gas prices declined and we continued to see pressure on basis differentials in the Marcellus. Although our long-term pricing contracts shielded us somewhat, price differentials in the Marcellus averaged US$1.50 per Mcf below NYMEX for the second quarter. Given the increasing supply outlook in the region, and our growing uncontracted production volumes, we are revising our Marcellus price differential outlook and expect to average a discount of US$1.35 per Mcf to NYMEX for calendar 2014.

With rising crude oil prices, we continued to hedge our future production volumes in order to protect a portion of our funds flow, and support our capital spending plans and dividend. We increased our hedges for 2015 significantly since the last quarter. We have now swapped half of our net oil production after royalties for the first six months of 2015 at an average price of US$93.58 per barrel. For the second half of 2015, we've swapped 26% of our net oil production after royalties at similar prices.

Our financial flexibility remains strong, ending the quarter with a trailing 12-month debt-to-funds flow ratio of 1.3x, unchanged from Q1 2014. We further strengthened our financial position entering into private placement agreements for a US$200 million offering of senior, twelve-year amortizing, unsecured notes at a fixed-rate coupon of 3.79%. We expect to close the offering in early September, and will use the proceeds to pay down our bank debt, replacing short-term, floating interest rate debt with long-term debt at an attractive fixed interest rate.

ENERPLUS 2014 Q2 REPORT 3

Production and Capital Spending

	Three months ended June 30, 2014			Six months ended June 30, 2014
	Average Production Volumes		Capital Spending ($ millions)	Average Production Volumes		Capital Spending ($ millions)

Crude Oil & NGLs (BOE/day)
Canada	19,660	$	28	19,390	$	91
United States	23,839		99	22,877		158

Total Crude Oil & NGLs (BOE/day)	43,499	$	127	42,267	$	249

Natural Gas (Mcf/day)
Canada	156,401	$	32	154,027	$	97
United States	206,528		45	200,879		76

Total Natural Gas (Mcf/day)	362,929	$	77	354,906	$	173

Company Total (BOE/day)	103,987	$	204	101,418	$	422

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

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

Crude Oil
Canada	1.5	1.1	6.9	–
United States	6.9	6.9	5.1	–

Total Crude Oil	8.4	8.0	12.0	–

Natural Gas
Canada	–	–	1.4	–
United States	5.9	4.6	5.9	–

Total Natural Gas	5.9	4.6	7.3	–

Company Total	14.3	12.6	19.3	–

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

Asset Activity

Our second quarter capital spending totaled $204 million, down slightly from the first quarter. This investment saw us drill 14.3 net horizontal wells and place 19.3 net wells on-stream, the majority of which were in our Bakken/Three Forks and Marcellus plays.

At Fort Berthold, we invested $98.6 million in the quarter with 6.9 net wells drilled targeting a mix of Bakken and Three Forks horizons. We also completed and brought on-stream 5.1 net wells, including our two top performing wells, one Bakken and one second bench Three Forks, which produced an average of approximately 2,400 barrels per day per well in their first 30 days (cumulative production of over 70,000 barrels of oil each). Daily production increased by 14% at Fort Berthold over the first quarter of 2014, averaging 20,800 BOE per day, a new high for this project.

In the Marcellus, our operations continued to be focused in Wyoming, Susquehanna, Bradford and Sullivan counties. During the quarter we invested $45.1 million, drilling and bringing on-stream 5.9 net wells. Production averaged a record 189 MMcf per day, up 5% compared to the first quarter of the year, and more than double from the production rate in the second quarter of 2013.

4 ENERPLUS 2014 Q2 REPORT

We also invested $28.1 million into our low-decline Canadian oil waterflood portfolio for both near and long-term growth, increasing production slightly quarter over quarter. At Brooks, we continued to advance our 60-well drilling program targeting the Lower Mannville sands and we are moving forward with the second phase of development in our polymer project at Medicine Hat.

Consistent with our on-going portfolio management, we expect to sell non-core gas weighted properties with production of 2,500 BOE to 3,500 BOE per day with closing early in the fourth quarter.

Summary

We have delivered another quarter of consistent operational execution which is driving production growth and further confirming the sustainability of our business. We are proud to be hitting record production levels while maintaining our capital discipline and strong financial position. We remain focused on achieving our operating and financial targets and creating value for our shareholders.

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

ENERPLUS 2014 Q2 REPORT 5

MD&A

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

The following discussion and analysis of financial results is dated August 7, 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 six months ended June 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 to evaluate 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 to analyze 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 June 30,					Six months ended June 30,
Reconciliation of Cash Flow from Operating Activities to Funds Flow		2014			2013		2014		2013

Cash flow from operating activities	$	228,506		$	195,424	$	368,916	$	356,658
Asset retirement obligation expenditures		4,240			2,957		8,532		6,335
Changes in non-cash operating working capital		(19,535	)		6,325		56,275		14,312

Funds flow	$	213,211		$	204,706	$	433,723	$	377,305

6 ENERPLUS 2014 Q2 REPORT

"Debt to Funds Flow Ratio" is used to analyze 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 to analyze 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

Our strong operational performance continued during the second quarter with production of 103,987 BOE/day, up 15% from the same period a year ago and up 5% from the prior quarter. Based on our year to date performance, we have increased our annual production guidance to 100,000-104,000 BOE/day from 96,000-100,000 BOE/day and are on track to deliver approximately 5% crude oil and liquids growth, with production of 44,000 bbls/day. Our capital program remained on track with spending of $204.4 million during the quarter and we are maintaining our capital spending guidance for 2014 of $800 million. With the strength of our balance sheet and the anticipated proceeds from our non-core divestments, we are evaluating opportunities to modestly increase spending in our core areas and plan to review spending levels in the third quarter.

Funds flow in the second quarter totaled $213.2 million compared to $204.7 million in the same period in 2013 and $220.5 million in the first quarter of 2014. The decrease in funds flow compared to the first quarter of 2014 was primarily a result of lower natural gas prices and a wider Marcellus differential to NYMEX, offset by higher crude oil prices. Operating costs and cash general and administrative costs came in better than expected at $10.09/BOE and $1.97/BOE, respectively, and as a result we are lowering our 2014 guidance for operating costs and cash general and administrative to $10.10/BOE (from $10.25/BOE) and $2.30/BOE (from $2.45/BOE). Our share price rose by approximately $4.80 or 22% during the second quarter, which led to an increase in our cash share-based compensation expense. Accordingly, we are increasing our cash share-based compensation guidance to $0.60/BOE from $0.45/BOE.

We continue to maintain our financial flexibility and strong balance sheet. Our trailing 12 month debt to funds flow ratio was 1.3x and we had $706.7 million of undrawn credit capacity at quarter end. In June, we signed agreements and priced a US$200.0 million private placement of senior unsecured notes with a ten year average life and an interest rate of 3.79%. The debt issue is expected to close in early September and proceeds will be used to repay outstanding debt.

RESULTS OF OPERATIONS

Production

Production increased by 5% to 103,987 BOE/day in the second quarter of 2014 from 98,821 BOE/day in the first quarter. Crude oil volumes grew by 6% due to our ongoing development program in Fort Berthold, while natural gas volumes rose by 5% as a result of the strong performance of our Marcellus assets.

Compared to the second quarter of 2013, production increased 15% or 13,950 BOE/day. Natural gas volumes grew by approximately 25% due to our ongoing development activity in the Marcellus, along with the December 2013 acquisition of additional working interests in our existing Marcellus properties. Over the same period, our crude oil volumes increased by approximately 5% due to growth in our Fort Berthold production volumes and despite divestments of approximately 2,100 BOE/day of non-core Canadian crude oil production in the second half of 2013.

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

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

	Three months ended June 30,			Six months ended June 30,
Average Daily Production Volumes	2014	2013	% Change	2014	2013	% Change

Crude oil (bbls/day)	39,863	38,066	5%	38,817	38,193	2%
Natural gas liquids (bbls/day)	3,636	3,497	4%	3,450	3,546	(3)%
Natural gas (Mcf/day)	362,929	290,841	25%	354,906	281,275	26%

Total daily sales (BOE/day)	103,987	90,037	15%	101,418	88,618	14%

ENERPLUS 2014 Q2 REPORT 7

As a result of strong operational performance, we are increasing our annual average production guidance to 100,000-104,000 BOE/day from 96,000-100,000 BOE/day, with crude oil and natural gas liquids expected to contribute approximately 44,000 bbls/day. This revised production guidance assumes anticipated divestments of non-core gas weighted properties in Canada with production of approximately 2,500 to 3,500 BOE/day in the fourth quarter.

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 six month period ended June 30, 2014 and 2013 and quarterly average prices from the second quarter of 2014 to the second quarter of 2013.

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

Benchmarks
	WTI crude oil (US$/bbl)	$	100.84		$	94.30		$	102.99		$	98.68		$	97.46		$	105.82		$	94.22
	AECO natural gas – monthly index (CDN$/Mcf)		4.72			3.34			4.68			4.76			3.16			2.82			3.59
	AECO natural gas – daily index (CDN$/Mcf)		5.20			3.37			4.69			5.71			3.53			2.43			3.53
	NYMEX natural gas – last day (US$/Mcf)		4.80			3.71			4.67			4.94			3.60			3.58			4.09
	US/CDN exchange rate		1.10			1.02			1.09			1.10			1.05			1.04			1.02
Enerplus selling price ⁽¹⁾
	Crude oil (CDN$/ bbl)	$	93.25		$	80.74		$	94.90		$	91.48		$	77.77		$	96.30		$	82.95
	Natural gas liquids (CDN$/ bbl)		57.66			52.16			49.98			66.30			54.26			49.88			45.64
	Natural gas (CDN$/ Mcf)		4.46			3.41			4.02			4.93			3.26			2.96			3.70

Average differentials (US$/bbl or US$/Mcf)
	MSW Edmonton – WTI	$	(7.19	)	$	(5.31	)	$	(6.13	)	$	(8.25	)	$	(14.93	)	$	(4.72	)	$	(3.67	)
	WCS Hardisty – WTI		(21.59	)		(25.56	)		(20.04	)		(23.13	)		(32.20	)		(17.48	)		(19.16	)
	Brent Futures (ICE) – WTI		7.97			13.69			6.75			9.19			11.86			3.83			9.14
	AECO monthly – NYMEX		(0.50	)		(0.43	)		(0.38	)		(0.63	)		(0.60	)		(0.86	)		(0.58	)
Enerplus realized differentials⁽¹⁾
	Canada crude oil – WTI	$	(19.19	)	$	(22.03	)	$	(17.80	)	$	(20.70	)	$	(30.73	)	$	(15.18	)	$	(16.97	)
	Canada natural gas – NYMEX		(0.51	)		(0.62	)		(0.71	)		(0.31	)		(0.63	)		(1.06	)		(0.78	)
	Bakken crude oil – WTI	$	(12.87	)	$	(7.89	)	$	(14.55	)		(11.85	)		(17.47	)		(11.41	)		(9.61	)
	Marcellus natural gas – NYMEX		(1.20	)		(0.11	)		(1.50	)		(0.88	)		(0.50	)		(0.52	)		(0.12	)

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

Crude Oil and Natural Gas Liquids

WTI prices increased by 4% during the second quarter of 2014 due to elevated tensions in the Middle East and decreased U.S. storage levels as refiners ran at high utilization rates. In particular, balances at Cushing, the WTI pricing hub, decreased significantly during the quarter due to increased take away. The market rallied strongly in June on fears of a potential supply disruption in Iraq, driving spot WTI prices to reach an intra-day high of US$107.73/bbl.

Crude oil differentials in Canada improved in the second quarter, with WCS averaging US$20.04/bbl below WTI and light sweet differentials averaging US$6.13/bbl below WTI. The improvement in differentials was largely due to scheduled maintenance by oil sands producers that restricted production during the period. We expect that incremental downstream pipeline capacity coming into service in the second half of 2014 will help support Canadian differential prices for the remainder of the year. Our realized differential for Canadian crude oil improved during the second quarter averaging US$17.80/bbl below WTI compared to US$20.70/bbl in the first quarter.

Our average realized Bakken differential widened during the quarter, to US$14.55/bbl below WTI from US$11.85/bbl in the first quarter, as our volumes being shipped by rail grew during the quarter and rail netbacks fell.

Natural Gas

U.S. natural gas prices weakened throughout the second quarter as injections into storage facilities were much higher compared to the same period in 2013 due to cooler than normal weather conditions across much of the key U.S. demand centres. In Canada, AECO differentials to NYMEX narrowed to US$0.38/Mcf below NYMEX during the second quarter compared to US$0.63/Mcf in the first quarter.

8 ENERPLUS 2014 Q2 REPORT

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. During the first quarter, our realized differentials were positively impacted by the volatility of the AECO daily index, while the second quarter saw no material differences between AECO month and day index.

Natural gas prices in the Marcellus weakened considerably in the second quarter as cooler temperatures resulted in lower than expected demand for gas-fired power generation. When combined with an estimated net supply increase of over 1.5 Bcf/day in the Northeast U.S. relative to last year, regional spot price differentials to NYMEX in the Marcellus widened from an average of approximately US$0.88/Mcf below NYMEX in April to as much as US$2.30/Mcf below NYMEX in June. Approximately 56% of our Marcellus production during the quarter was exposed to these regional spot prices contributing to our realized Marcellus price differential of US$1.50/Mcf below NYMEX for the quarter. We now expect an annual realized Marcellus price differential of US$1.35/Mcf below NYMEX for 2014.

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. Following a rapid depreciation of the Canadian dollar in the first quarter of 2014, the dollar regained some ground in the second quarter supported by higher oil prices and rising inflation. After reaching a low of 1.1251 near the close of the first quarter, the Canadian dollar rose to 1.0676 at June 30, 2014. As the dollar weakened in the first quarter, we entered into costless collars on our oil and gas sales to protect a portion of our anticipated revenues at favorable exchange rates.

Price Risk Management

We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions. We have increased our crude oil hedges significantly since last quarter. As of July 23, 2014 we have swapped an average of 21,000 bbls/day from July 1, 2014 to December 31, 2014 at an average price of US$95.42/bbl, which represents approximately 68% of our forecasted net crude oil production after royalties. For the first half of 2015, we have swapped 15,500 bbls/day at an average price of US$93.58/bbl, which represents approximately 50% of our forecasted net crude oil production after royalties. Additionally, we have 8,000 bbls/d swapped for the second half of 2015 at an average price of US$93.86/bbl, which represents approximately 26% of our forecasted net crude oil production after royalties.

We have entered into WCS differential swap positions for 2014 to manage our exposure to widening heavy crude oil differentials. These differential swaps have been fixed at an average price of WTI less a fixed spread of US$21.00/bbl on 3,000 bbls/day from July through September of 2014 and 4,000 bbls/day from October through December of 2014. We have also entered into 3,000 bbl/day of Brent-WTI differential swap positions for the remainder of 2014 to shift some of our WTI price exposure to Brent based pricing, selling WTI at an average of 92.63% of Brent pricing.

As of July 23, 2014 we have downside protection on approximately 50% of our forecasted natural gas production after royalties for the remainder of 2014 consisting of NYMEX swaps at US$4.14/Mcf on 28% of production, NYMEX collars at US$4.30 – $5.08/Mcf on 11% of production and AECO swaps at an average price of $4.25/Mcf on 11% of production. Overall for 2015, we have downside protection on approximately 23% of our forecasted annual natural gas production after royalties comprised of NYMEX swaps at an average price of US$4.26/Mcf on 20% of production and NYMEX collars in the first quarter at US$4.53 -$5.53/Mcf on 3% of forecasted annual production.

We have foreign exchange costless collars in place 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 July 23, 2014 we have US$12.0 million per month hedged for the remainder of 2014 at an average USD/CDN floor of 1.1046, ceiling of 1.1558 and conditional ceiling of 1.1198. Under these contracts, if the monthly foreign exchange rate settles above the ceiling rate the conditional ceiling is used to determine the settlement amount. For 2015, we have US$12.0 million per month hedged at an average USD/CDN floor of 1.1083, ceiling of 1.1900 and conditional ceiling of 1.1254. During the second quarter, we recorded cash gains of $0.4 million and non-cash mark-to-market gains of $6.7 million on the contracts.

ENERPLUS 2014 Q2 REPORT 9

The following is a summary of our financial contracts in place at July 23, 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⁾

Jul 1,
2014 –
Sep 30,
2014

Oct 1,
2014 –
Dec 31,
2014

Jan 1,
2015 –
Jun 30,
2015

Jul 1,
2015 –
Dec 31,
2015

Jul 1,
2014 –
Dec 31,
2014

Jan 1,
2015 –
Mar 31,
2015

Apr 1,
2015 –
Jun 30,
2015

Jul 1,
2015 –
Dec 31,
2015

Purchased Puts

–

4.30

4.53

–

11%

–

Sold Puts

–

3.23

–

Swaps

95.54

95.29

93.58

93.86

4.25

4.14

4.31

4.21

71%

65%

50%

26%

11%

28%

24%

17%

Sold Calls

–

5.04

5.53

–

20%

11%

–

Purchased Calls

–

4.17

–

(1): Based on weighted average price (before premiums), assumed average annual production of 100,000 – 104,000 BOE/day for 2014 and 2015, less royalties and production taxes of 23% in aggregate.

ACCOUNTING FOR PRICE RISK MANAGEMENT

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

Cash gains/(losses):
	Crude oil	$	(21.2	)	$	11.0		$	(32.0	)	$	21.9
	Natural gas		(3.3	)		(1.9	)		(7.9	)		(1.2	)

Total cash gains/(losses)		$	(24.5	)	$	9.1		$	(39.9	)	$	20.7
Non-cash gains/(losses):
	Change in fair value – crude oil	$	(24.8	)	$	8.7		$	(34.2	)	$	(20.9	)
	Change in fair value – natural gas		5.3			12.8			(2.6	)		3.8

Total non-cash gains/(losses)		$	(19.5	)	$	21.5		$	(36.8	)	$	(17.1	)

Total gains/(losses)		$	(44.0	)	$	30.6		$	(76.7	)	$	3.6

	Three months ended June 30,					Six months ended June 30,
(Per BOE)		2014			2013		2014			2013

Total cash gains/(losses)	$	(2.60	)	$	1.11	$	(2.17	)	$	1.29
Total non-cash gains/(losses)		(2.06	)		2.63		(2.01	)		(1.07	)

Total gains/(losses)	$	(4.66	)	$	3.74	$	(4.18	)	$	0.22

During the second quarter of 2014, we realized cash losses of $21.2 million on our crude oil contracts and $3.3 million on our natural gas contracts. In comparison, during the second quarter of 2013, we realized cash gains of $11.0 million on our crude oil contracts and cash losses of $1.9 million on our natural gas contracts. The cash losses realized in 2014 were a result of crude oil and natural gas prices rising above our fixed price swap positions. The crude oil cash gains in 2013 were due to 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 second quarter of 2014 the fair value of our crude oil

10 ENERPLUS 2014 Q2 REPORT

and natural gas contracts represented net loss positions of $49.0 million and $2.3 million, respectively. For the three and six months ended June 30, 2014 the change in the fair value of our crude oil contracts represented losses of $24.8 million and $34.2 million, respectively, while the change in fair value of our natural gas contracts represented a gain of $5.3 million and a loss of $2.6 million, respectively.

Revenues

	Three months ended June 30,						Six months ended June 30,
($ millions)		2014			2013			2014			2013

Oil and natural gas sales	$	504.5		$	404.8		$	999.5		$	778.2
Royalties		(89.6	)		(63.5	)		(176.9	)		(123.5	)

Oil and natural gas sales, net of royalties	$	414.9		$	341.3		$	822.6		$	654.7

Oil and natural gas sales were $504.5 million in the second quarter of 2014, an increase of 25% or $99.7 million compared to the same period in 2013. For the six months ended June 30, 2014 oil and natural gas sales were $999.5 million, an increase of 28% or $221.3 million compared to the same period a year ago. The increase in revenues was related to higher production and improved realized prices.

Royalties and Production Taxes

	Three months ended June 30,				Six months ended June 30,
($ millions)		2014		2013		2014		2013

Royalties	$	89.6	$	63.5	$	176.9	$	123.5
Production taxes		20.0		17.9		39.8		32.5

Royalties and production taxes	$	109.6	$	81.4	$	216.7	$	156.0

As a % of oil and natural gas sales, net of transportation		22%		20%		22%		20%

	Three months ended June 30,				Six months ended June 30,
(Per BOE)		2014		2013		2014		2013

Royalties	$	9.47	$	7.75	$	9.64	$	7.70
Production taxes		2.11		2.18		2.17		2.03

Royalties and production taxes	$	11.58	$	9.93	$	11.81	$	9.73

As a % of oil and natural gas sales, net of transportation		22%		20%		22%		20%

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees, freehold mineral taxes and Saskatchewan resource surcharges. During the three and six months ended June 30, 2014 royalties and production taxes increased to $109.6 million and $216.7 million, respectively, from $81.4 million and $156.0 million for the same period a year ago. This upward trend is primarily due to higher realized prices and increased production from higher royalty rate U.S. properties. Royalties and production taxes averaged 22% of oil and gas sales (net of transportation) in 2014 compared to 20% in 2013.

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

Operating Expenses

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

Operating Expenses	$	95.5	$	85.4	$	184.6	$	166.7
Per BOE	$	10.09	$	10.42	$	10.06	$	10.39

ENERPLUS 2014 Q2 REPORT 11

Our operating expenses for the three and six months ended June 30, 2014 were $95.5 million or $10.09/BOE and $184.6 million or $10.06/BOE respectively. In comparison, we had operating costs of $85.4 million or $10.42/BOE and $166.7 million or $10.39/BOE for the same periods in 2013. The current year operating costs have decreased on a per BOE basis mainly due to the higher production from our lower cost Marcellus and Fort Berthold properties.

Based on our increased production guidance and continued focus on cost control, we are reducing our annual guidance for operating costs to $10.10/BOE from $10.25/BOE.

Transportation Costs

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

Transportation costs	$	13.1	$	6.2	$	26.2	$	13.4
Per BOE	$	1.39	$	0.76	$	1.43	$	0.84

Transportation costs for the three and six months ended June 30, 2014 were $13.1 million and $26.2 million, respectively, compared to $6.2 million and $13.4 million 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 six months ended June 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 June 30, 2014
Netbacks by Property Type		Crude Oil			Natural Gas			Total

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

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

Oil and natural gas sales⁽²⁾	$	86.94		$	4.26		$	51.93
Royalties and production taxes		(21.06	)		(0.74	)		(11.58	)
Cash operating costs		(13.17	)		(1.30	)		(10.12	)

Netback before hedging	$	52.71		$	2.22		$	30.23

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

Netback after hedging	$	47.48		$	2.12		$	27.63

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

Netback after hedging ($ millions)	$	193.1		$	68.4		$	261.5

12 ENERPLUS 2014 Q2 REPORT

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

Average Daily Production		42,753 BOE/day			283,704 Mcfe/day			90,037 BOE/day

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

Oil and natural gas sales⁽²⁾	$	75.70		$	4.03		$	48.65
Royalties and production taxes		(17.13	)		(0.57	)		(9.93	)
Cash operating costs		(13.19	)		(1.36	)		(10.55	)

Netback before hedging	$	45.38		$	2.10		$	28.17

Cash gains/(losses)		2.82			(0.07	)		1.11

Netback after hedging	$	48.20		$	2.03		$	29.28

Netback before hedging ($ millions)	$	176.6		$	54.2		$	230.8

Netback after hedging ($ millions)	$	187.5		$	52.4		$	239.9

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

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

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

Oil and natural gas sales⁽²⁾	$	86.29		$	4.67		$	53.03
Royalties and production taxes		(21.19	)		(0.79	)		(11.81	)
Cash operating costs		(13.28	)		(1.28	)		(10.07	)

Netback before hedging	$	51.82		$	2.60		$	31.15

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

Netback after hedging	$	47.77		$	2.47		$	28.98

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

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

	Six months ended June 30, 2013
Netbacks by Property Type		Crude Oil			Natural Gas			Total

Average Daily Production		42,684 BOE/day			275,604 Mcfe/day			88,618 BOE/day

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

Oil and natural gas sales⁽²⁾	$	74.25		$	3.83		$	47.68
Royalties and production taxes		(16.70	)		(0.54	)		(9.73	)
Cash operating costs		(13.01	)		(1.36	)		(10.48	)

Netback before hedging	$	44.54		$	1.93		$	27.47

Cash gains/(losses)		2.83			(0.02	)		1.29

Netback after hedging	$	47.37		$	1.91		$	28.76

Netback before hedging ($ millions)	$	344.1		$	96.5		$	440.6

Netback after hedging ($ millions)	$	366.0		$	95.3		$	461.3

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

Our crude oil properties accounted for 71% of our corporate netback before hedging for the year to date compared to 78% for the same period in 2013. Crude oil netbacks per BOE increased for the three and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to higher realized crude oil prices partially offset by higher royalties as a result of increased U.S. production. Natural gas netbacks per Mcfe decreased slightly during the second quarter compared to the same period last year due to weakened gas prices and widening differentials. Strong gas prices in the first quarter led to an increase in the natural gas netback for the six months ended June 30, 2014 compared to the same period in 2013.

ENERPLUS 2014 Q2 REPORT 13

General and Administrative Expenses ("G&A")

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 June 30,						Six months ended June 30,
($ millions)		2014			2013			2014			2013

Cash:
G&A expense⁽¹⁾	$	18.7		$	18.8		$	39.2		$	43.5
SBC		10.7			3.7			17.5			9.2
Non-Cash:
SBC		3.5			3.0			6.5			5.5
SBC – equity swap loss/(gain)		(4.7	)		(0.8	)		(5.9	)		(2.3	)

Total G&A expenses	$	28.2		$	24.7		$	57.3		$	55.9

	Three months ended June 30,						Six months ended June 30,
(Per BOE)		2014			2013			2014			2013

Cash:
G&A expense⁽¹⁾	$	1.97		$	2.29		$	2.14		$	2.71
SBC		1.12			0.45			0.95			0.57
Non-Cash:
SBC		0.37			0.36			0.35			0.34
SBC – equity swap loss/(gain)		(0.49	)		(0.09	)		(0.32	)		(0.14	)

Total G&A expenses	$	2.97		$	3.01		$	3.12		$	3.48

(1): Excluding SBC.

Cash G&A expenses during the second quarter were in line with our expectations at $18.7 million or $1.97/BOE compared to $18.8 million or $2.29/BOE in the second quarter of 2013. For the six months ended June 30, 2014 cash G&A expenses were $39.2 million or $2.14/BOE compared to $43.5 million or $2.71/BOE for the same period in 2013. The decrease during 2014 was mainly due to one-time charges recorded in the prior year associated with the departure of personnel. Higher production volumes in 2014 have also helped to decrease our reported G&A on a per BOE basis.

Cash SBC expense increased during 2014 due to the increase in our share price, which had risen by 39% during the six months ended June 30, 2014. For the second quarter of 2014, cash SBC expense was $10.7 million or $1.12/BOE compared to $3.7 million or $0.45/BOE during the second quarter of 2013. For the six months ended June 30, 2014 cash SBC expense was $17.5 million or $0.95/BOE compared to $9.2 million or $0.57/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 $14.78/share. As a result of the increase in our share price we recorded non-cash mark-to-market gains of $4.7 million and $5.9 million for the three and six months ended June 30, 2014, respectively.

We are reducing our 2014 guidance for cash G&A expense to $2.30/BOE from $2.45/BOE based on our revised production guidance and continued focus on cost control. We are also increasing our 2014 guidance for cash SBC to $0.60/BOE from $0.45/BOE based on our share price at June 30, 2014.

Interest Expense

	Three months ended June 30,				Six months ended June 30,
($ millions)		2014		2013		2014		2013

Interest on senior notes and bank facility	$	16.0	$	14.3	$	30.6	$	28.5
Non-cash interest expense		0.5		0.5		1.1		0.7

Total interest expense	$	16.5	$	14.8	$	31.7	$	29.2

14 ENERPLUS 2014 Q2 REPORT

For the three and six months ended June 30, 2014 we recorded total interest expense of $16.5 million and $31.7 million, respectively, compared to $14.8 million and $29.2 million in the same periods in 2013. Despite a decreasing debt balance, interest on our senior notes increased slightly year over year due to the impact of a weaker Canadian dollar on our U.S. dollar denominated interest payments.

Non-cash amounts recorded in interest expense include unrealized gains and losses resulting from the change in fair value of the interest component of our cross currency interest rate swap ("CCIRS") and amortization of deferred financing charges.

At June 30, 2014, after including our underlying derivatives, approximately 72% of our debt was based on fixed interest rates and 28% on floating interest rates.

Foreign Exchange

	Three months ended June 30,						Six months ended June 30,
($ millions)		2014			2013			2014			2013

Realized loss/(gain)	$	16.6		$	14.9		$	16.7		$	17.6
Unrealized loss/(gain)		(23.8	)		(12.7	)		(22.5	)		(11.1	)

Total foreign exchange loss/(gain)	$	(7.2	)	$	2.2		$	(5.8	)	$	6.5

We recorded a net foreign exchange gain of $7.2 million during the second quarter and a gain of $5.8 million year to date, compared to net losses of $2.2 million and $6.5 million during the same periods in 2013.

On June 19, 2014 we made the final US$35.0 million principal repayment on our US$175.0 million senior notes and corresponding CCIRS settlement, which resulted in a $15.8 million realized foreign exchange loss. The remaining realized losses during the quarter related to day-to-day transactions denominated in foreign currencies.

Unrealized foreign exchange gains in the quarter related to the translation of our U.S. dollar debt and working capital and the reversal of cumulative mark-to-market losses on the final settlement of our CCIRS.

Capital Investment and Dispositions

	Three months ended June 30,					Six months ended June 30,
($ millions)		2014		2013			2014			2013

Capital spending	$	204.4	$	139.7		$	422.2		$	312.6
Office capital		1.2		0.8			1.6			2.2

Sub-total	$	205.6	$	140.5		$	423.8		$	314.8

Property and land acquisitions	$	3.2	$	51.7		$	13.2		$	55.7
Property dispositions		0.5		(71.3	)		(116.7	)		(72.6	)

Sub-total	$	3.7	$	(19.6	)	$	(103.5	)	$	(16.9	)

Total net capital investment	$	209.3	$	120.9		$	320.3		$	297.9

Capital spending for the second quarter totaled $204.4 million compared to $139.7 million during the same period in 2013. We continue to focus our spending on our core development areas. Crude oil spending for the quarter included $98.6 million at Fort Berthold and $28.1 million on our Canadian waterflood properties. Natural gas spending included $45.1 million in the Marcellus and $31.0 million on our Deep Basin assets.

We completed minor property and land acquisitions totaling $3.2 million during the quarter. In the second quarter of 2013 we spent $51.7 million, which included $34.0 million for the acquisition of an incremental 50% working interest in our Pouce Coupe light oil waterflood property as well as $16.7 million on land acquisitions around our existing acreage in the U.S.

Property dispositions of $71.3 million in the second quarter of 2013 included the sale of our Taylorton and Turner Valley non-core oil asset for proceeds of $57.2 million along with other minor dispositions totaling $14.1 million.

ENERPLUS 2014 Q2 REPORT 15

We are maintaining our capital spending guidance at $800 million. However, given the strength of our balance sheet and anticipated divestment proceeds, we are evaluating opportunities in our core areas and may modestly increase spending in the second half of the year.

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

	Three months ended June 30,				Six months ended June 30,
($ millions, except per BOE amounts)		2014		2013		2014		2013

DDA&A expense	$	148.7	$	160.5	$	280.8	$	306.7
Per BOE	$	15.71	$	19.59	$	15.30	$	19.12

DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three and six months ended June 30, 2014 DDA&A decreased to $148.7 million and $280.8 million, respectively, compared to $160.5 million and $306.7 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 in 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 by Enerplus based on our net ownership interest, anticipated costs to abandon and reclaim and the timing of the costs to be incurred in future periods. We have estimated the net present value of our asset retirement obligation to be $288.6 million at June 30, 2014 compared to $291.8 million at December 31, 2013.

Income Taxes

	Three months ended June 30,				Six months ended June 30,
($ millions)		2014		2013		2014		2013

Current tax expense	$	3.8	$	1.4	$	11.5	$	2.7
Deferred tax expense		12.7		20.3		37.2		22.2

Total tax expense	$	16.5	$	21.7	$	48.7	$	24.9

We recorded total tax expense of $16.5 million and $48.7 million for the three and six months ended June 30, 2014, respectively, compared to $21.7 million and $24.9 million for the same periods in 2013. For the three months ended June 30, 2014 the decrease in total tax expense relates primarily to the decrease in net income for tax purposes. For the six months ended June 30, 2014 higher revenues caused net income for tax purposes to increase resulting in an increase in tax expense.

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. Based on current commodity prices and assuming no acquisition and divestment activity, we expect to pay U.S. cash taxes of between 3% to 5% of our U.S. funds flow for 2014 and 2015. We expect to continue to pay U.S. AMT through 2018 with the rate gradually increasing to approximately 15% over that time. We currently do not expect to pay material cash taxes in Canada until after 2018.

16 ENERPLUS 2014 Q2 REPORT

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

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

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

Average Daily Production Volumes⁽¹⁾
	Crude oil (bbls/day)		17,184			22,679			39,863			18,364			19,702			38,066
	Natural gas liquids (bbls/day)		2,476			1,160			3,636			2,975			522			3,497
	Natural gas (Mcf/day)		156,401			206,528			362,929			186,569			104,272			290,841

	Total average daily production (BOE/day)		45,727			58,260			103,987			52,434			37,603			90,037

Pricing⁽²⁾
	Crude oil (per bbl)	$	92.90		$	96.41		$	94.90		$	79.06		$	86.58		$	82.95
	Natural gas liquids (per bbl)		57.01			35.00			49.98			49.05			26.21			45.64
	Natural gas (per Mcf)		4.32			3.80			4.02			3.39			4.26			3.70
Capital Expenditures
	Capital spending	$	60.4		$	144.0		$	204.4		$	44.4		$	95.3		$	139.7
	Acquisitions		–			3.2			3.2			35.0			16.7			51.7
	Dispositions		–			0.5			0.5			(63.9	)		(7.4	)		(71.3	)
Netback Before Hedging
	Oil and natural gas sales	$	226.0		$	278.5		$	504.5		$	208.9		$	195.9		$	404.8
	Royalties		(35.1	)		(54.5	)		(89.6	)		(25.5	)		(38.0	)		(63.5	)
	Operating expense		(62.2	)		(33.5	)		(95.7	)		(64.9	)		(21.5	)		(86.4	)
	Production taxes		(1.9	)		(18.1	)		(20.0	)		(5.0	)		(12.9	)		(17.9	)
	Transportation expense		(5.9	)		(7.2	)		(13.1	)		(5.4	)		(0.8	)		(6.2	)

	Netback before hedging	$	120.9		$	165.2		$	286.1		$	108.1		$	122.7		$	230.8

Other Expenses
	Commodity derivative instruments loss/(gain)	$	44.0		$	–		$	44.0		$	30.6			–		$	30.6
	General and administrative expense		22.6			5.6			28.2			21.1			3.6			24.7
	Current income tax expense/(recovery)		(0.2	)		4.0			3.8			0.1			1.3			1.4

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

ENERPLUS 2014 Q2 REPORT 17

		Six months ended June 30, 2014									Six months ended June 30, 2013
(CDN$ millions, except per unit amounts)			Canada			U.S.			Total			Canada			U.S.			Total

Average Daily Production Volumes⁽¹⁾
	Crude oil (bbls/day)		16,882			21,935			38,817			18,764			19,429			38,193
	Natural gas liquids (bbls/day)		2,508			942			3,450			3,045			501			3,546
	Natural gas (Mcf/day)		154,027			200,879			354,906			182,214			99,061			281,275

	Total average daily production (BOE/day)		45,061			56,357			101,418			52,178			36,440			88,618

Pricing⁽²⁾
	Crude oil (per bbl)	$	89.55		$	96.09		$	93.25		$	73.44		$	87.80		$	80.74
	Natural gas liquids (per bbl)		63.16			43.01			57.66			55.81			30.02			52.16
	Natural gas (per Mcf)		4.70			4.28			4.46			3.15			3.90			3.41
Capital Expenditures
	Capital spending	$	188.0		$	234.2		$	422.2		$	127.4		$	185.2		$	312.6
	Acquisitions		–			13.2			13.2			37.6			18.1			55.7
	Dispositions		(67.7	)		(49.0	)		(116.7	)		(65.2	)		(7.4	)		(72.6	)
Netback Before Hedging
	Oil and natural gas sales	$	446.0		$	553.5		$	999.5		$	397.1		$	381.1		$	778.2
	Royalties		(69.1	)		(107.8	)		(176.9	)		(50.4	)		(73.1	)		(123.5	)
	Operating expense		(124.4	)		(60.4	)		(184.8	)		(131.4	)		(36.8	)		(168.2	)
	Production taxes		(3.9	)		(35.9	)		(39.8	)		(6.4	)		(26.1	)		(32.5	)
	Transportation expense		(11.7	)		(14.5	)		(26.2	)		(11.8	)		(1.6	)		(13.4	)

	Netback before hedging	$	236.9		$	334.9		$	571.8		$	197.1		$	243.5		$	440.6

Other Expenses
	Commodity derivative instruments loss/(gain)	$	76.7		$	–		$	76.7		$	3.6		$	–		$	3.6
	General and administrative expense		45.9			11.4			57.3			49.0			6.9			55.9
	Current income tax expense/(recovery)		(0.4	)		11.9			11.5			0.1			2.6			2.7

(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
(CDN$ millions, except per share amounts)		Royalties		Income/(Loss)			Basic			Diluted

2014
Second Quarter	$	414.9	$	40.0		$	0.20		$	0.19
First Quarter		407.7		40.0			0.20			0.19

Total	$	822.6	$	80.0		$	0.39		$	0.39

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	)

Oil and gas sales increased in the second quarter of 2014 due to higher production volumes which were partially offset by lower realized natural gas prices compared to the first quarter. Oil and gas sales grew during 2013 with increasing production volumes. Net income grew in 2014 compared to 2013 from increased production and realized prices. Net income in 2012 was lower due to asset impairments recorded during the year.

18 ENERPLUS 2014 Q2 REPORT

LIQUIDITY AND CAPITAL RESOURCES

We continued to maintain a strong balance sheet and ample liquidity through the second quarter. At June 30, 2014 we had a conservative trailing 12 month debt to cash flow ratio of 1.3x and approximately $706.7 million of undrawn credit capacity. On June 19, 2014 we made the final principal payment on our US$175.0 million senior notes and the related CCIRS settlement. During the quarter, we entered into agreements to issue US$200.0 million of senior unsecured notes on a private placement basis. The notes, which are expected to close on September 3, 2014, have a twelve year amortizing term with a ten year average life and a fixed interest rate of 3.79%. We plan to use the proceeds to repay our short-term, floating interest rate bank debt.

Our adjusted payout ratio, calculated as dividends (net of SDP proceeds) plus capital and office spending, divided by funds flow, increased to 120% and 119% for the three and six months ended June 30, 2014, respectively, compared to 89% and 106% for the same periods in 2013. Although funds flow increased by 4% and 15% for the three and six months ended June 2014 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.

Total debt net of cash at June 30, 2014 was $1,067.6 million, including current portion, compared to $1,022.3 million at December 31, 2013. Total debt was comprised of $293.3 million of bank indebtedness and $776.3 million of senior notes, less $2.0 million in cash. Our working capital deficiency, excluding cash and current deferred financial and tax assets and credits, increased slightly during the quarter to $251.2 million from $226.1 million. Although receivables increased due to higher production levels, this was offset by a higher current portion of long-term debt related to senior note maturities in June of 2015. 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 June 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.

Dividends

	Three months ended June 30,				Six months ended June 30,
($ millions, except per share amounts)		2014		2013		2014		2013

Cash dividends	$	50.5	$	42.6	$	92.7	$	86.3
Stock dividend plan		4.7		11.4		17.4		21.5

Total dividends to shareholders	$	55.2	$	54.0	$	110.1	$	107.8

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

During the three and six months ended June 30, 2014 we recorded dividends to our shareholders of $55.2 million ($0.27/share) and $110.1 million ($0.54/share), respectively, compared to $54.0 million ($0.27/share) and $107.8 million ($0.54/share) for the same periods in 2013. For the first six months of 2014, dividend payments including SDP amounted to 25% of our funds flow of $433.7 million. We will continue to assess 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.

Participation in the SDP is optional allowing our shareholders to continue to receive cash dividends unless they elect to receive stock dividends. As a result of our improved sustainability and strong balance sheet, in April of this year we eliminated the 5% discount with the intention of reducing shareholder dilution. Subsequently, our participation rate in the SDP decreased significantly to approximately 9% where we had

ENERPLUS 2014 Q2 REPORT 19

previously been averaging 23%. Participation in the SDP for July was approximately $1.7 million compared to approximately $4.2 million per month in the first quarter.

Shareholders' Capital

	Six months ended June 30,
		2014		2013

Share capital ($ millions)	$	3,102.2	$	3,019.2
Common shares outstanding (thousands)		204,768		200,268
Weighted average shares outstanding – basic (thousands)		203,671		199,430
Weighted average shares outstanding – diluted (thousands)		207,563		199,586

During the second quarter of 2014, a total of 929,000 shares (2013 – 805,000) and $17.8 million of additional equity (2013 – $11.4 million) was issued pursuant to the SDP and the stock option plan. For the six months ended June 30, 2014, a total of 2,010,000 shares (2013 – 1,584,000) and $36.7 million of additional equity (2013 – $21.5 million) was issued pursuant to the SDP and the stock option plan.

At June 30, 2014 we had 204,768,000 shares outstanding (2013 – 200,268,000) and at August 7, 2014 we had 205,229,771 shares outstanding.

U.S. Filing Status

Pursuant to U.S. securities regulations, we are required to reassess our U.S. securities filing status annually at June 30. As at June 30, 2014 we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.

2014 GUIDANCE

A summary of our 2014 guidance is below.

Summary of 2014 Expectations		Target

Average annual production		100,000 – 104,000 BOE/day (from 96,000 – 100,000 BOE/day)
Production mix (volumes)		44,000 bbls/day crude oil and liquids 56,000-60,000 BOE/day natural gas
Capital spending		$800 million
Average royalty rate (% of gross sales, net of transportation)		23% (from 23.5%)
Operating costs		$10.10/BOE (from $10.25/BOE)
Cash G&A expenses		$2.30 (from $2.45/BOE)
Cash share-based compensation expenses		$0.60/BOE (from $0.45/BOE)
U.S. Cash taxes (% of U.S. funds flow)		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 June 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 April 1, 2014 and ending June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

20 ENERPLUS 2014 Q2 REPORT

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 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; the amount and timing of future debt issuances and expected use of proceeds therefrom; and future dispositions and acquisitions, including 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, 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 Q2 REPORT 21

STATEMENTS

Condensed Consolidated Balance Sheets

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

Assets
Current assets
	Cash		$	1,998		$	2,990
	Accounts receivable	3		201,323			165,091
	Deferred income tax asset			21,961			48,476
	Deferred financial assets	15		17,534			9,198
	Other current assets			7,528			7,641

				250,344			233,396

Property, plant and equipment
	Oil and natural gas properties (full cost method)	4		2,471,732			2,420,144
	Other capital assets, net	4		18,839			21,210

	Property, plant and equipment			2,490,571			2,441,354

Goodwill				610,575			609,975
Deferred income tax asset				355,467			364,411
Deferred financial assets		15		25,926			19,274
Marketable securities		5		–			13,389

Total Assets			$	3,732,883		$	3,681,799

Liabilities
Current liabilities
	Accounts payable	6	$	347,349		$	377,157
	Dividends payable			18,454			18,250
	Current portion of long-term debt	7		94,234			48,713
	Deferred financial credits	15		58,956			37,031

				518,993			481,151

Long-term debt		7		975,354			976,585
Asset retirement obligation		8		288,627			291,761

				1,263,981			1,268,346

Total Liabilities				1,782,974			1,749,497

Shareholders' Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2014 – 205 million shares December 31, 2013 – 203 million shares		14		3,102,202			3,061,839
Paid-in capital		14		41,209			38,398
Accumulated deficit				(1,147,393	)		(1,117,238	)
Accumulated other comprehensive income/(loss)				(46,109	)		(50,697	)

				1,949,909			1,932,302

Total Liabilities & Equity			$	3,732,883		$	3,681,799

Contingencies and Commitments		16

See accompanying notes to the Condensed Consolidated Financial Statements

22 ENERPLUS 2014 Q2 REPORT

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

			Three months ended June 30,					Six months ended June 30,
(CDN$ thousands) unaudited		Note		2014			2013		2014			2013

Revenues
Oil and natural gas sales, net of royalties		9	$	414,925		$	341,324	$	822,665		$	654,705
Commodity derivative instruments gain/(loss)		15		(44,069	)		30,622		(76,666	)		3,567

				370,856			371,946		745,999			658,272

Expenses
Operating				95,509			85,369		184,590			166,714
Production taxes				19,974			17,860		39,846			32,482
Transportation				13,139			6,232		26,248			13,429
General and administrative		10		28,180			24,666		57,303			55,875
Depletion, depreciation, amortization and accretion				148,656			160,526		280,836			306,749
Interest		11		16,522			14,800		31,701			29,237
Foreign exchange (gain)/loss		12		(7,225	)		2,184		(5,756	)		6,536
Other expense/(income)				(360	)		157		2,552			284

				314,395			311,794		617,320			611,306

Income/(Loss) Before Taxes				56,461			60,152		128,679			46,966
Current income tax expense/(recovery)		13		3,797			1,401		11,475			2,708
Deferred income tax expense/(recovery)		13		12,707			20,284		37,210			22,188

Net Income/(Loss)			$	39,957		$	38,467	$	79,994		$	22,070

Other Comprehensive Income/(Loss)
Changes due to marketable securities (net of tax)
	Unrealized gain/(loss)			–			2,345		(145	)		2,860
	Realized (gain)/loss reclassified to net income			–			–		2,503			(190	)
Change in cumulative translation adjustment				(43,414	)		37,790		2,230			58,643

Other Comprehensive Income/(Loss)				(43,414	)		40,135		4,588			61,313

Total Comprehensive Income/(Loss)			$	(3,457	)	$	78,602	$	84,582		$	83,383

Net Income/(Loss) per Share
Basic			$	0.20		$	0.19	$	0.39		$	0.11
Diluted			$	0.19		$	0.19	$	0.39		$	0.11

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2014 Q2 REPORT 23

Condensed Consolidated Statements of Changes
in Shareholders' Equity

Six months ended June 30, (CDN$ thousands) unaudited			2014			2013

Share Capital
Balance, beginning of year		$	3,061,839		$	2,997,682
Stock Option Plan – cash			19,193			29
Share-based compensation – non cash			3,683			3
Stock Dividend Plan			17,487			21,495

Balance, end of period		$	3,102,202		$	3,019,209

Paid-in Capital
Balance, beginning of year		$	38,398		$	32,293
Stock Option Plan – exercised			(3,683	)		(3	)
Share-based compensation – expensed			6,494			5,478

Balance, end of period		$	41,209		$	37,768

Accumulated Deficit
Balance, beginning of year		$	(1,117,238	)	$	(948,350	)
Net income			79,994			22,070
Dividends			(110,149	)		(107,794	)

Balance, end of period		$	(1,147,393	)	$	(1,034,074	)

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	)		2,860
	Realized gains/loss reclassified to net income		2,503			(190	)
Change in cumulative translation adjustment			2,230			58,643

Balance, end of period		$	(46,109	)	$	(69,072	)

Total Shareholders' Equity		$	1,949,909		$	1,953,831

See accompanying notes to the Condensed Consolidated Financial Statements

24 ENERPLUS 2014 Q2 REPORT

Condensed Consolidated Statements of Cash Flows

			Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) unaudited		Note		2014			2013			2014			2013

Operating Activities
Net income/(loss)			$	39,957		$	38,467		$	79,994		$	22,070
Non-cash items add/(deduct):
	Depletion, depreciation, amortization and accretion			148,656			160,526			280,836			306,749
	Changes in fair value of derivative instruments	15		130			(47,943	)		6,939			(13,889	)
	Deferred income tax expense/(recovery)	13		12,707			20,284			37,210			22,188
	Foreign exchange (gain)/loss on debt and working capital	12		(9,052	)		12,218			1,935			16,538
	Share-based compensation	14		3,542			2,951			6,494			5,478
	Amortization of debt issue costs			247			192			493			377
Derivative settlement on senior notes				17,024			18,011			17,024			18,011
Asset disposition (gain)/loss				–			–			2,798			(217	)
Asset retirement obligation expenditures		8		(4,240	)		(2,957	)		(8,532	)		(6,335	)
Changes in non-cash operating working capital		17		19,535			(6,325	)		(56,275	)		(14,312	)

Cash flow from operating activities				228,506			195,424			368,916			356,658

Financing Activities
Proceeds from the issuance of shares				13,055			8			19,193			29
Cash dividends		14		(50,508	)		(42,620	)		(92,662	)		(86,299	)
Change in bank debt				107,280			14,670			76,710			70,089
Repayment of senior notes				(37,898	)		(35,655	)		(37,898	)		(35,655	)
Derivative settlement on senior notes				(17,024	)		(18,011	)		(17,024	)		(18,011	)
Changes in non-cash financing working capital				103			81			204			151

Cash flow from financing activities				15,008			(81,527	)		(51,477	)		(69,696	)

Investing Activities
Capital expenditures				(205,623	)		(140,465	)		(423,816	)		(314,841	)
Property and land acquisitions				(3,231	)		(51,692	)		(13,200	)		(55,659	)
Property dispositions				(525	)		71,293			116,700			72,624
Sale of marketable securities		5		–			–			13,300			1,883
Changes in non-cash investing working capital				(35,482	)		10,012			(10,805	)		20,735

Cash flow from investing activities				(244,861	)		(110,852	)		(317,821	)		(275,258	)

Effect of exchange rate changes on cash				(2,392	)		(4,842	)		(610	)		(6,148	)

Change in cash				(3,739	)		(1,797	)		(992	)		5,556
Cash, beginning of period				5,737			12,553			2,990			5,200

Cash, end of period			$	1,998		$	10,756		$	1,998		$	10,756

See accompanying notes to the Condensed Consolidated Financial Statements

ENERPLUS 2014 Q2 REPORT 25

NOTES

Notes to Condensed Consolidated Financial Statements
(unaudited)

1) REPORTING ENTITY

These interim Condensed Consolidated Financial Statements ("interim Consolidated Financial Statements") and notes present the financial position and results of Enerplus Corporation ("The Company" or "Enerplus") including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus' head office is located in Calgary, Alberta, Canada. The interim Consolidated Financial Statements were authorized for issue by the Board of Directors on August 7, 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 June 30, 2014 and for the three and six months ended June 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.

3) ACCOUNTS RECEIVABLE

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

Accrued receivables	$	154,290		$	122,482
Accounts receivable – trade		33,906			36,034
Current income tax receivable		15,960			9,371
Allowance for doubtful accounts		(2,833	)		(2,796	)

Total accounts receivable	$	201,323		$	165,091

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

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

Oil and natural gas properties	$	11,807,080	$	9,335,348	$	2,471,732
Other capital assets		91,493		72,654		18,839

Total PP&E	$	11,898,573	$	9,408,002	$	2,490,571

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 six months ended June 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.

26 ENERPLUS 2014 Q2 REPORT

6) ACCOUNTS PAYABLE

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

Accrued payables	$	262,213	$	262,117
Accounts payable – trade		85,136		115,040

Total accounts payable	$	347,349	$	377,157

7) DEBT

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

Current:
	Senior notes	$	94,234	$	48,713

		$	94,234	$	48,713

Long term:
	Bank credit facility	$	293,263	$	214,394
	Senior notes		682,091		762,191

		$	975,354	$	976,585

Total debt		$	1,069,588	$	1,025,298

8) ASSET RETIREMENT OBLIGATION

Enerplus has estimated the present value of its asset retirement obligation to be $288.6 million at June 30, 2014 compared to $291.8 million at December 31, 2013, based on a total undiscounted liability of $714.5 million and $720.6 million, respectively. The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.93% at June 30, 2014 (December 31, 2013 – 5.96%).

($ thousands)		Six months ended June 30, 2014			Year ended December 31, 2013

Balance, beginning of year	$	291,761		$	256,102
Change in estimates		(2,175	)		44,217
Property acquisition and development activity		1,039			1,454
Dispositions		(927	)		(8,362	)
Settlements		(8,532	)		(16,606	)
Accretion Expense		7,461			14,956

Balance, end of period	$	288,627		$	291,761

9) OIL AND NATURAL GAS SALES

		Three months ended June 30,						Six months ended June 30,
($ thousands)			2014			2013			2014			2013

	Oil and natural gas sales	$	504,551		$	404,827		$	999,575		$	778,252
	Royalties⁽¹⁾		(89,626	)		(63,503	)		(176,910	)		(123,547	)

Oil and natural gas sales, net of royalties		$	414,925		$	341,324		$	822,665		$	654,705

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

ENERPLUS 2014 Q2 REPORT 27

10) GENERAL AND ADMINISTRATIVE EXPENSE

	Three months ended June 30,				Six months ended June 30,
($ thousands)		2014		2013		2014		2013

General and administrative expense	$	18,672	$	18,804	$	39,201	$	43,483
Share-based compensation expense⁽¹⁾		9,508		5,862		18,102		12,392

General and administrative expense	$	28,180	$	24,666	$	57,303	$	55,875

(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 June 30,					Six months ended June 30,
($ thousands)			2014		2013			2014		2013

Realized: Interest on bank debt and senior notes		$	15,962	$	14,291		$	30,628	$	28,477
Unrealized:
	Cross currency interest rate swap (gain)/loss		313		488			580		820
	Interest rate swap (gain)/loss		–		(171	)		–		(437	)
	Amortization of debt issue costs		247		192			493		377

Interest expense		$	16,522	$	14,800		$	31,701	$	29,237

12) FOREIGN EXCHANGE

		Three months ended June 30,						Six months ended June 30,
($ thousands)			2014			2013			2014			2013

Realized:
	Foreign exchange (gain)/loss	$	16,626		$	14,867		$	16,676		$	17,599
Unrealized:
	Translation of U.S. dollar debt and working capital (gain)/loss		(9,052	)		12,218			1,935			16,538
	Cross currency interest rate swap (gain)/loss		(14,885	)		(18,970	)		(16,130	)		(19,982	)
	Foreign exchange derivative (gain)/loss		86			(5,931	)		(8,237	)		(7,619	)

Foreign exchange (gain)/loss		$	(7,225	)	$	2,184		$	(5,756	)	$	6,536

13) INCOME TAXES

		Three months ended June 30,					Six months ended June 30,
($ thousands)			2014			2013		2014			2013

Current tax expense/(recovery)
	Canada	$	(190	)	$	77	$	(374	)	$	81
	U.S.		3,987			1,324		11,849			2,627

Current tax expense/(recovery)			3,797			1,401		11,475			2,708

Deferred tax expense/(recovery)
	Canada	$	(7,005	)	$	9,957	$	(5,318	)	$	(2,512	)
	U.S.		19,712			10,327		42,528			24,700

Deferred tax expense/(recovery)		$	12,707		$	20,284	$	37,210		$	22,188

Income tax expense/(recovery)		$	16,504		$	21,685	$	48,685		$	24,896

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

28 ENERPLUS 2014 Q2 REPORT

differentials, the reversal or recognition of previously unrecognized deferred tax assets, non-taxable portions of capital gains and losses, and non-deductible share based compensation.

14) SHAREHOLDERS' EQUITY

a) Share Capital

		Six months ended June 30,			Year ended December 31,

		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	1,165		19,193	1,042		14,838
Non-cash:
	Stock Option Plan	–		3,683	–		3,108
	Stock Dividend Plan	845		17,487	3,032		46,211

Balance, end of period		204,768	$	3,102,202	202,758	$	3,061,839

b) Dividends

	Three months ended June 30,				Six months ended June 30,
($ thousands)		2014		2013		2014		2013

Cash dividends	$	50,508	$	42,620	$	92,662	$	86,299
Stock dividends		4,706		11,389		17,487		21,495

Dividends to shareholders	$	55,214	$	54,009	$	110,149	$	107,794

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 June 30,						Six months ended June 30,
($ thousands)			2014			2013			2014			2013

Cash:
	Long-term incentive plans expense	$	10,648		$	3,687		$	17,512		$	9,205
Non-Cash:
	Long-term incentive plans expense		2,856			–			3,691			–
	Stock option plan expense		686			2,951			2,803			5,478
	Equity swap (gain)/loss		(4,682	)		(776	)		(5,904	)		(2,291	)

Share-based compensation expense		$	9,508		$	5,862		$	18,102		$	12,392

(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.

ENERPLUS 2014 Q2 REPORT 29

The following table summarizes the Performance Share Unit ("PSU"), Restricted Share Unit ("RSU") and Director Share Unit ("DSU") activity for the six months ended June 30, 2014:

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

Balance, beginning of year		650		821		99	1,570
Granted		543		811		47	1,401
Vested		–		(305	)	–	(305	)
Forfeited		(16	)	(40	)	–	(56	)

Balance, end of period		1,177		1,287		146	2,610

End of period balances, by grant settlement type:
	Cash-settled units	637		498		146	1,281
	Equity-settled units	540		789		–	1,329

Balance, end of period		1,177		1,287		146	2,610

Cash-settled LTI Plans

For the three and six months ended June 30, 2014 the Company recorded cash SBC expense of $10.6 million and $17.5 million, respectively (June 30, 2013 – $3.7 million and $9.2 million) and for the three and six months ended June 30, 2014, made $0.3 million and $11.8 million, respectively in cash payments related to its cash-settled plans (June 30, 2013 – $0.4 million and $6.9 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 June 30, 2014 ($ thousands, except for years)		PSU⁽¹⁾		RSU		DSU		Total

Cumulative recognized SBC expense	$	21,641	$	10,527	$	4,161	$	36,329
Unrecognized SBC expense		11,689		4,025		–		15,714

Intrinsic value	$	33,330	$	14,552	$	4,161	$	52,043

Weighted-average remaining contractual term (years)		1.1		0.9		–

(1): Includes estimated performance multipliers.

Equity-settled LTI Plans

With equity-settled LTI awards being settled through the issuance of treasury shares, 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 six months ended June 30, 2014 the Company recorded non-cash SBC expense of $2.9 million and $3.7 million, respectively. No non-cash amounts were recognized for the three and six months ended June 30, 2013 with respect to the 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 June 30, 2014 ($ thousands, except for years)		PSU⁽¹⁾		RSU		Total

Cumulative recognized SBC expense	$	881	$	2,810	$	3,691
Unrecognized SBC expense		6,860		10,916		17,776

	$	7,741	$	13,726	$	21,467

Weighted-average remaining contractual term (years)		2.5		1.7

(1): Includes estimated performance multipliers.

30 ENERPLUS 2014 Q2 REPORT

(ii) Stock Option Plan

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

		Six months ended June 30, 2014

		Number of Options (thousands)			Weighted Average Exercise Price

Options outstanding
Beginning of year		13,414		$	18.65
	Granted	–			–
	Exercised	(1,165	)		16.48
	Forfeited	(396	)		20.28
	Expired	–			–

Options outstanding, end of period		11,853		$	18.81

Options exercisable at the end of period		6,136		$	21.97

At June 30, 2014, 6,136,000 options were exercisable at a weighted average reduced exercise price of $21.97 with a weighted average remaining contractual term of 4.2 years, giving an intrinsic value of $36.7 million (June 30, 2013 – $1.4 million). The intrinsic value of options exercised during the three and six months ended June 30, 2014 was $5.2 million and $8.1 million, respectively (June 30, 2013 – $nil and $nil).

At June 30, 2014 the unrecognized SBC expense related to non-vested options was $2.5 million (June 30, 2013 – $8.2 million). The expense is expected to be fully recognized over a weighted-average period of 1.1 years.

d) Paid-in Capital

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

($ thousands)		Six months ended June 30, 2014			Year ended December 31, 2013

Balance, beginning of year	$	38,398		$	32,293
Stock Option Plan – exercised		(3,683	)		(3,108	)
Share-based compensation – non-cash		6,494			9,213

Balance, end of period	$	41,209		$	38,398

e) Basic and Diluted Earnings Per Share

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

		Three months ended June 30,				Six months ended June 30,
(thousands, except per share amounts)			2014		2013		2014		2013

Net income/(loss)		$	39,957	$	38,467	$	79,994	$	22,070
Weighted average shares outstanding – Basic			204,158		199,825		203,671		199,430
Dilutive impact of share-based compensation			4,364		294		3,892		156

Weighted average shares outstanding – Diluted			208,522		200,119		207,563		199,586

Net income/(loss) per share
	Basic		0.20		0.19		0.39		0.11
	Diluted		0.19		0.19		0.39		0.11

ENERPLUS 2014 Q2 REPORT 31

15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At June 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 June 30, 2014 senior notes included in long-term debt had a carrying value of $776.3 million and a fair value of $806.6 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 six months ended June 30, 2014 and 2013:

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

Interest Rate Swaps			$	–		$	171		$	–		$	436		Interest
Cross Currency Interest Rate Swap:
	Interest			(313	)		(488	)		(580	)		(820	)	Interest
	Foreign Exchange			14,885			18,970			16,130			19,982		Foreign Exchange
Foreign Exchange Derivatives				(86	)		5,931			8,237			7,619		Foreign Exchange
Electricity Swaps				228			1,061			182			1,470		Operating
Equity Swaps				4,682			776			5,904			2,291		General and Administrative
Commodity Derivative Instruments:
		Oil		(24,810	)		8,685			(34,203	)		(20,892	)	Commodity derivative
		Gas		5,284			12,837			(2,609	)		3,803		instruments Gain/(loss)

Total			$	(130	)	$	47,943		$	(6,939	)	$	13,889

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

	Three months ended June 30,					Six months ended June 30,
($ thousands)		2014			2013		2014			2013

Change in fair value gain/(loss)	$	(19,526	)	$	21,522	$	(36,812	)	$	(17,089	)
Net realized cash gain/(loss)		(24,543	)		9,100		(39,854	)		20,656

Commodity derivative instruments gain/(loss)	$	(44,069	)	$	30,622	$	(76,666	)	$	3,567

32 ENERPLUS 2014 Q2 REPORT

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

		June 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			4,275		19,661		–		564		15,135		–
Electricity Swaps			91		–		–		–		–		95
Equity Swaps			5,500		6,265		–		1,723		4,139		–
Commodity Derivative Instruments:
	Oil		1,378		–		50,412		4,138		–		18,970
	Gas		6,290		–		8,544		2,773		–		2,418

Total		$	17,534	$	25,926	$	58,956	$	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.

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 July 23, 2014:

Crude Oil Instruments:

Instrument Type	bbls/day	US$/bbl⁽¹⁾

Jul 1, 2014 – Sep 30, 2014
WTI Swap	22,000	95.54
WCS Differential Swap	3,000	-21.00
Brent – WTI Ratio Spread (% of Brent Price)	3,000	92.63%
Oct 1, 2014 – Dec 31, 2014
WTI Swap	20,000	95.29
WCS Differential Swap	4,000	-21.00
Brent – WTI Ratio Spread (% of Brent Price)	3,000	92.63%
Jan 1, 2015 – Jun 30, 2015
WTI Swap	15,500	93.58
Jul 1, 2015 – Dec 31, 2015
WTI Swap	8,000	93.86

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

ENERPLUS 2014 Q2 REPORT 33

Natural Gas Instruments:

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

Jul 1, 2014 – Dec 31, 2014
AECO Swap	28.4	4.25
Jul 1, 2014 – Dec 31, 2014
NYMEX Swap	75.0		4.14
NYMEX Purchased Put	30.0		4.30
NYMEX Purchased Call	25.0		4.17
NYMEX Sold Put	25.0		3.23
NYMEX Sold Call	55.0		5.04
Jan 1, 2015 – Mar 31, 2015
NYMEX Swap	65.0		4.31
NYMEX Purchased Put	30.0		4.53
NYMEX Sold Call	30.0		5.53
Apr 1, 2015 – Jun 30, 2015
NYMEX Swap	65.0		4.31
Jul 1, 2015 – Dec 31, 2015
NYMEX Swap	45.0		4.21

Electricity Instruments:

Instrument Type	MWh	CDN$/MWh

Jul 1, 2014 – Dec 31, 2014
AESO Power Swap	16.0	53.33
Jan 1, 2015 – Dec 31, 2015
AESO Power Swap	16.0	50.79
Jan 1, 2016 – Dec 31, 2016
AESO Power Swap	3.0	50.50

Physical Contracts:

Instrument Type	MMcf/day	US$/Mcf

Jul 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	)

34 ENERPLUS 2014 Q2 REPORT

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes and working capital. Additionally, Enerplus' crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. Enerplus manages currency risk relating to its senior notes through the derivative instruments detailed below.

Foreign Exchange Derivatives:

During the six months ended June 30, 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 July 23, 2014:

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

Jun 1, 2014 – Dec 31, 2014	12.0	1.1046	1.1558	1.1198
Jan 1, 2015 – Dec 31, 2015	12.0	1.1083	1.1900	1.1254

(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 June 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 June 30, 2014, approximately 72% of Enerplus' debt was based on fixed interest rates and 28% was based on floating interest rates. At June 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 2013 and 2016 and has effectively fixed the future settlement cost on 995,000 shares at a weighted average price of $14.78 per share.

(ii) Credit Risk

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

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

Enerplus' maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At June 30, 2014 approximately 73% of Enerplus' marketing receivables were with companies considered investment grade.

ENERPLUS 2014 Q2 REPORT 35

At June 30, 2014 approximately $1.1 million or 0.5% 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 June 30, 2014 was $2.8 million (December 31, 2013 – $2.8 million).

(iii) Liquidity Risk & Capital Management

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

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

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.

During the quarter, Enerplus entered into an agreement to extend its Calgary head office lease for an additional 5 years through 2024, which including operating costs, is expected to amount to approximately $57 million over the additional term.

17) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

	Three months ended June 30,						Six months ended June 30,
($ thousands)		2014			2013			2014			2013

Accounts receivable	$	12,292		$	(11,365	)	$	(19,877	)	$	(15,197	)
Other current assets		(379	)		(202	)		544			(1,189	)
Accounts payable		7,622			5,242			(36,942	)		2,074

	$	19,535		$	(6,325	)	$	(56,275	)	$	(14,312	)

b) Other

	Three months ended June 30,				Six months ended June 30,
($ thousands)		2014		2013		2014		2013

Income taxes paid/(received)	$	18,521	$	356	$	18,387	$	(4,890	)
Interest paid	$	26,305	$	26,347	$	28,688	$	29,221

36 ENERPLUS 2014 Q2 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): Chairman of the Corporate Governance & Nominating Committee
(5): Member of the Audit & Risk Management Committee
(6): Chairman of the Audit & Risk Management Committee
(7): Member of the Reserves Committee
(8): Chairman of the Reserves Committee
(9): Member of the Compensation & Human Resources Committee
(10): Chairman of the Compensation & Human Resources Committee
(11): Member of the Safety & Social Responsibility Committee
(12): Chairman of the Safety & Social Responsibility Committee

ENERPLUS 2014 Q2 REPORT 37

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

38 ENERPLUS 2014 Q2 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 Q2 REPORT 39

QuickLinks

Exhibit 99.1

Financial Leverage and Coverage

June 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⁾