CALGARY, Aug. 8, 2014 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce strong operational and financial results for the second quarter of 2014.

HIGHLIGHTS:

• Enerplus achieved record production of approximately 104,000 BOE per day in the second quarter of 2014, the highest level in our 28 year history. Daily production was up 5% quarter over quarter, and 15% higher than the same period one year ago.
  
  
• Total 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 continued operational outperformance, we are increasing our annual average production guidance for 2014 by 4,000 BOE per day to 100,000 BOE per day to 104,000 BOE per day. We continue to expect liquids production to grow throughout the remainder of the year and to average approximately 44,000 barrels per day in 2014. Natural gas production is expected to continue to grow ahead of expectations due to the performance in the Marcellus.
  
  
• The new, higher production guidance 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.
  
  
• Capital spending was in line with expectations at $204 million, with almost 50% allocated to the Fort Berthold project. As announced on June 18, 2014, our development activity over the past three years has significantly increased the value of this asset. Our best estimate of economic contingent resources increased by 250% to 136 million BOE and our drilling inventory increased by 125% to approximately 330 net drilling locations. This represents 16 years of future drilling at our current pace.
  
  
• 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.
  
  
• Operating costs were essentially unchanged from the first quarter of 2014 averaging $10.09 per BOE in the second quarter. Cash general and administrative costs per BOE decreased by approximately 15% from the first quarter and averaged $1.97 per BOE. With the expected increase in annual production for 2014, we are reducing our outlook for operating costs to $10.10 per BOE, down from our previous estimate of $10.25 per BOE. Cash G&A costs are now forecast at $2.30 per BOE, down from $2.45 per BOE previously.
  
  
• Funds flow increased by 4% compared to the same period last year. Compared to the first quarter of 2014, funds flow declined modestly to $213 million in the second quarter due to a 20% drop in realized natural gas prices, despite the growth in production and higher crude oil prices.
  
  
• Both AECO and NYMEX gas prices declined during the second quarter and we continued to see pressure on Marcellus basis differentials. Although our long-term pricing contracts shielded us somewhat, price differentials in the quarter averaged US$1.50 per Mcf below NYMEX. Given the increasing supply outlook in the region and the growth of our 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.
  
  
• We increased our 2015 hedges significantly during the quarter. We have now swapped half of our expected 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 have swapped 26% of our net expected oil production, after royalties, at similar prices.
  
  
• Our financial flexibility remains strong with our trailing twelve-month debt-to-funds flow ratio unchanged from the first quarter at 1.3x. To further strengthen our financial position, we entered into private placement agreements for a US$200 million offering of senior, twelve-year amortizing, unsecured notes at a fixed coupon rate of 3.79%. We expect to close the offering in early September and expect to 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.

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/(Loss)					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
	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)
	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 our second quarter MD&A.

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

					Three months ended June 30,										Six months ended June 30,
					2014					2013					2014					2013
Average Benchmark Pricing
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					CDN* - ERF					U.S.** - ERF
For the three months ended June 30, 2014					(CDN$)					(US$)
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.

Production and Capital Spending
					Three months ended June 30, 2014										Six months ended June 30, 2014
Crude Oil & NGLs (BOE/day)					Average Production Volumes					Capital Spending ($ millions)					Average Production Volumes					Capital Spending ($ millions)
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
Crude Oil					Horizontal Wells					Wells Pending Completion/ Tie-in *					Wells On-stream**					Dry & Abandoned Wells
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.

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 strategy, 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.

2014 Guidance Update

A summary of our revised 2014 guidance is outlined below.

2014 Expectations	Target
Average annual production	100,000 - 104,000 BOE/day (from 96,000 - 100,000 BOE/day)
Production mix (volume)	44,000 bbls/day crude oil and natural gas 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/BOE (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%

Conference Call Details

A conference call hosted by Ian C. Dundas, President and CEO will be held at 8:30AM MT (10:30AM ET) today to discuss these results. Details of the conference call are as follows:

Live Conference Call

Date:	Friday, August 8, 2014
Time:	8:30AM MT / 10:30AM ET
Dial-In:	647-427-7450
	888-231-8191 (toll free)
	Passcode: 76199864
Audiocast:	http://www.newswire.ca/en/webcast/detail/1387835/1539723

To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A podcast of the conference call will be available on our website for downloading. A telephone replay will be available for 30 days following the conference call. The telephone replay can be accessed at the following numbers:

Dial-In:	416-849-0833
	1-855-859-2056 (toll free)
Passcode:	76199864

Electronic copies of our Second Quarter 2014 MD&A and Financial Statements, along with other public information including investor presentations, are available on our website at www.enerplus.com. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.

Currency and Accounting Principles

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

Barrels of Oil Equivalent

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

Presentation of Production Information

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

See "Non-GAAP Measures" below.

Contingent Resource Estimates

This news release contains estimates of contingent resources. Contingent resources are not, and should not be confused with, oil and gas reserves. Contingent resources are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economics, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. All of our contingent resource estimates are economic using established technologies and under current commodity price assumptions used by our independent reserve evaluators. Enerplus expects to develop these contingent resources in the coming years however it is too early in their development for these resources to be classified as reserves at this time. There is no certainty that it will be commercially viable or that we will produce any portion of the volumes currently classified as contingent resources. The contingent resource estimates contained herein are presented as the best estimate of the quantity that will actually be recovered, effective as of June 1, 2014. A best estimate of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

For additional information regarding the primary contingencies which currently prevent the classification of our disclosed contingent resources associated with our Fort Berthold properties as reserves and the positive and negative factors relevant to the contingent resource estimates, see page 19 of our Annual Information Form dated February 21, 2014, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is available under our EDGAR profile at www.sec.gov.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "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 news release contains forward-looking information pertaining to the following: Enerplus' asset portfolio; future capital and development expenditures and the allocation thereof among our assets; future development and drilling locations, plans and costs; the performance of and future results from Enerplus' assets and operations, including anticipated production levels, expected ultimate recoveries and decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves and contingent resource volumes and future commodity price, differentials and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; potential asset dispositions and timing thereof; rates of return on Enerplus' capital program; Enerplus' tax position; sources of funding of Enerplus' capital program; the amount and timing of future debt issuances and expected use of proceeds therefrom; and future costs, expenses and royalty rates.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; 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 Enerplus' reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements as needed; and the extent of its liabilities. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from development plans or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; inaccurate estimation of Enerplus' oil and gas reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F described above).

The purpose of certain financial outlook information included in this news release, including with respect to our 2014 guidance for funds flow, is to communicate our current expectations as to our performance in 2014. Readers are cautioned that it may not be appropriate for other purposes. The forward-looking information contained in this news release speaks only as of the date of this news release, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

NON-GAAP MEASURES

In this news release, we use the terms "funds flow" and "debt-to-funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Debt-to-funds flow ratio" is used to analyze leverage and liquidity and is calculated as total debt net of cash, divided by a trailing 12 months of funds flow.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow" and "debt-to-funds flow ratio" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers.

SOURCE Enerplus Corporation

For further information:

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation