Enerplus Announces Strong Second Quarter 2015 Results

All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under "Non-GAAP Measures". This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Forward-Looking Information and Statements" at the conclusion of this news release. A full copy of our Second Quarter 2015 Financial Statements and MD&A are available on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov.

CALGARY, Aug. 7, 2015 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) announces the results from operations for the second quarter of 2015.

HIGHLIGHTS:

• Through the second quarter of 2015, Enerplus delivered production growth, improved cost performance and maintained a strong financial position.
  
  
• Production volumes grew by 7% quarter over quarter to 107,429 BOE per day. This growth was primarily driven by increased activity in North Dakota, where production averaged approximately 27,100 BOE per day, up over 25% from the first quarter of 2015. We also saw growth from our gas portfolio with our Canadian Deep Basin and Marcellus assets showing production increases over the first quarter of 2015. Our production mix was essentially unchanged from the previous quarter, with crude oil and natural gas liquids accounting for 43% of production.
  
  
• As a result of continued operational outperformance, we are increasing our average annual production guidance range to 100,000 – 104,000 BOE per day from 97,000 – 103,000 BOE per day. We expect approximately 44,000 – 46,000 barrels per day of crude oil and natural gas liquids. This guidance takes into account year to date divestments of approximately 1,900 BOE per day.
  
  
• We spent $148 million in our core areas during the quarter, and are on track to meet our annual capital spending guidance of $540 million, despite the weak Canadian dollar. Approximately 75% of spending in the quarter was directed to our North Dakota properties. In total we drilled 7.8 net wells and brought 22 net wells on-stream across our portfolio in the second quarter.
  
  
• Both operating costs and G&A expenses for the quarter came in lower than forecast, at $7.85 per BOE and $2.03 per BOE, respectively. Based on our cost savings realized to date and our increased production target, we are decreasing our annual operating cost guidance to $9.25 per BOE from $9.75 per BOE and our G&A expense guidance to $2.25 per BOE from $2.40 per BOE, representing a combined decrease of $0.65 per BOE.
  
  
• Funds flow increased by 47% to $160 million from the first quarter primarily due to higher production, lower costs and improved crude oil prices, and despite slightly weaker gas pricing.
  
  
• Our hedging program generated gains of $73 million during the second quarter.
  
  
• We reported a net loss of $312.5 million for the quarter as we incurred a non-cash asset impairment charge in the quarter of $497 million. Under U.S. GAAP we are required to use twelve month trailing average prices to determine impairment, and consequently the impairment reflects the low commodity prices in the fourth quarter of 2014 and the first half of 2015.
  
  
• During the quarter, we closed our previously announced non-core asset sales, along with the sale of additional minor non-core properties for proceeds of $188 million.
  
  
• After adjusting for divestment proceeds, our adjusted payout ratio for the first six months of 2015 was 75%.
  
  
• We ended the quarter with an improved debt to funds flow ratio of 1.6 times, down from 1.7 times in the first quarter of 2015. At June 30, 2015, we were approximately 8% drawn on our $1 billion credit facility. Following the next scheduled repayment of our senior notes in October 2015 of US$10.8 million, we have no scheduled debt repayments until June 2017.

"We believe our second quarter results demonstrate our commitment to maintaining our financial strength, focusing on productivity improvements and cost control measures, and maintaining our disciplined approach to capital allocation. Our goal of a fully funded program in 2015 remains intact and we have significant flexibility to navigate through this challenging market," said Ian C. Dundas, President & CEO.

SELECTED FINANCIAL RESULTS

	Three months ended June 30,		Six months ended June 30,
	2015	2014	2015	2014
Financial (000's)
Funds Flow^(4)	$      160,436	$        213,211	$      269,600	$      433,723
Cash and Stock Dividends	30,935	55,214	78,294	110,149
Net Income/(Loss)	(312,544)	39,957	(605,750)	79,994
Debt Outstanding – net of cash	1,120,680	1,067,590	1,120,680	1,067,590
Capital Spending	147,979	204,427	314,989	422,190
Property Divestments	187,801	(525)	191,513	116,700
Debt to Funds Flow Ratio^(4)	1.6x	1.3x	1.6x	1.3x
Financial per Weighted Average Shares Outstanding
Funds Flow	$           0.78	$              1.04	$             1.31	$            2.13
Net Income/(Loss)	(1.52)	0.20	(2.94)	0.39
Weighted Average Number of Shares Outstanding (000's)	206,208	204,158	206,028	203,671
Selected Financial Results per BOE^(1)(2)
Oil & Natural Gas Sales^(3)	$         30.53	$            53.32	$           28.78	$          54.45
Royalties and Production Taxes	(6.23)	(11.58)	(5.88)	(11.81)
Commodity Derivative Instruments	7.47	(2.60)	8.48	(2.17)
Cash Operating Expenses	(8.12)	(9.12)	(8.81)	(9.04)
Transportation Costs	(2.87)	(2.39)	(2.89)	(2.45)
General and Administrative	(2.03)	(1.97)	(2.19)	(2.14)
Cash Share-Based Compensation	0.13	(1.12)	(0.32)	(0.95)
Interest, Foreign Exchange and Other Expenses	(2.48)	(1.61)	(2.87)	(1.63)
Taxes	0.01	(0.40)	-	(0.63)
Funds Flow	$         16.41	$            22.53	$           14.30	$          23.63

SELECTED OPERATING RESULTS

	Three months ended June 30,		Six months ended June 30,
	2015	2014	2015	2014
Average Daily Production^(2)
Crude Oil (bbls/day)	41,122	39,863	40,243	38,817
Natural Gas Liquids (bbls/day)	5,145	3,636	4,444	3,450
Natural Gas (Mcf/day)	366,971	362,929	356,836	354,906
Total (BOE/day)	107,429	103,987	104,160	101,418
% Crude Oil and Natural Gas Liquids	43%	42%	43%	42%
Average Selling Price ^(2)(3)
Crude Oil (per bbl)	$              58.26	$             96.46	$        51.35	$          93.25
Natural Gas Liquids (per bbl)	20.88	51.80	21.55	57.66
Natural Gas (per Mcf)	2.09	4.15	2.32	4.46
Net Wells Drilled	8	14	36	44

(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)	Before transportation costs, royalties and commodity derivative instruments.
(4)	These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures" section in the following MD&A.

	Three months ended June 30,		Six months ended June 30,
Average Benchmark Pricing	2015	2014	2015	2014
WTI Crude Oil (US$/bbl)	$          57.94	$           102.99	$          53.29	$        100.84
AECO – monthly index (CDN$/Mcf)	2.67	4.68	2.81	4.72
AECO – daily index (CDN$/Mcf)	2.64	4.69	2.70	5.20
NYMEX – last day (US$/Mcf)	2.64	4.67	2.81	4.80
US/CDN exchange rate	1.23	1.09	1.24	1.10
Share Trading Summary	CDN*   ERF		U.S.** - ERF
For three months ended June 30, 2015	(CDN$)		(US$)
High	16.09		13.16
Low	10.61		8.56
Close	10.96		8.79

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

2015 Dividends per Share
Payment Month	CDN$	US$^(1)
First Quarter Total	$0.27	$0.22
April	0.05	0.04
May	0.05	0.04
June	0.05	0.04
Second Quarter Total	0.15	0.12
Total Year-to-Date	0.42	0.34

(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, 2015		Six months ended June 30, 2015
Crude Oil & NGLs (bbls/day)	Average Production  Volumes	Capital Spending ($ millions)	Average Production Volumes	Capital Spending ($ millions)
Canada	17,598	17.3	18,460	72.4
United States	28,669	110.8	26,227	189.2
Total Crude Oil & NGLs (bbls/day)	46,267	128.1	44,687	261.6
Natural Gas (Mcf/day)
Canada	144,788	7.3	140,129	29.1
United States	222,183	12.6	216,707	24.3
Total Natural Gas (Mcf/day)	366,971	19.9	356,836	53.4
Company Total (BOE/day)	107,429	148.0	104,160	315.0

Net Drilling Activity*** – for the three months ended June 30, 2015

Crude Oil	Wells Drilled	Wells Pending  Completion/ Tie-in *	Wells On-stream**	Dry & Abandoned Wells
Canada	1.0	1.0	6.6	-
United States	5.5	4.5	9.2	-
Total Crude Oil	6.5	5.5	15.8	-
Natural Gas
Canada	0.7	0.7	3.0	-
United States	0.7	0.4	3.2	-
Total Natural Gas	1.4	1.1	6.2	-
Company Total	7.8	6.5	22.0	-

*	Wells drilled during the quarter pending potential completion/tie-in or abandonment as at June 30, 2015.
**	Total wells brought on-stream during the quarter regardless of when they were drilled.
***	Table may not add due to rounding.

Asset Activity

We re-established production growth in North Dakota in the second quarter of 2015. Production from Fort Berthold averaged 27,100 BOE per day during the quarter, up over 25% from the first quarter of 2015. We drilled 5.5 net wells in Fort Berthold with 9.2 net wells brought on-stream during the quarter for a total capital outlay of $111 million. 

We continue to run a one-rig drilling program as we work through our inventory of drilled uncompleted wells at Fort Berthold and expect to drill approximately 8 net wells in the second half of the year. We are ahead of schedule on our 2015 completions activity. During the first six months of 2015 we brought approximately 13 net wells on-stream. We expect to bring up to 10 additional net wells on-stream during the second half of the year. This activity is broadly weighted towards the third quarter and we expect production growth through the remainder of the year. Our high intensity completion design continues to yield excellent results. The average initial 30 day production rate (IP30) of our operated on-stream wells in the quarter was over 2,000 BOE per day, exceeding our high end type curve. We continue to see improved well costs with current costs down over 20% from 2014 levels.

In the Marcellus, continued low levels of spending ($12.6 million in the second quarter) led to 0.7 net wells drilled and 3.2 net wells on-stream. Despite the reduced activity, well outperformance resulted in production of 201 MMcf per day during the second quarter, a modest increase from the previous quarter.

In the Deep Basin, we drilled three excellent wells at our Ansell pad. The average peak 30 day production rate for a well on the pad was approximately 10 MMcf per day, on trend with our high end type curve.

Crude Oil & Natural Gas Pricing

The West Texas Intermediate (WTI) benchmark price for crude oil increased by 19% quarter-over-quarter to average US$57.94 per barrel in the second quarter. The strength in WTI prices combined with the narrowing of crude oil differentials in both Canada and the U.S. resulted in a 32% improvement in the selling price for our crude oil compared to the previous quarter. The average realized sales price for our crude oil was $58.26 per barrel during the quarter with crude oil properties generating approximately 90% of our corporate netback.

On the natural gas side, both AECO and NYMEX weakened from the previous quarter due to continued high production and increased storage levels across the continent. In the Marcellus, our realized differential widened US$0.07 per Mcf from the previous quarter to average US$1.39 per Mcf. Overall, as a result of lower benchmark pricing and continued pricing weakness in the Marcellus producing region, our realized sales price for gas fell by 19% compared to the previous quarter to average $2.09 per Mcf.

We continued to add to our commodity hedge position for both 2015 and 2016. For the second half of 2015, we have an average of 11,250 barrels per day of crude oil hedged (representing approximately 35% of our expected crude oil production net of royalties) at an average floor price of US$84.58 per barrel through a combination of swaps and three way collar structures. For 2016, we have an average of 11,000 barrels per day of crude oil hedged (representing approximately 34% of our expected crude oil production net of royalties) at an average floor price of US$64.35 per barrel through a combination of swaps and three way collar structures.

We have also added to our NYMEX gas hedging position. For the second half of 2015, we are swapped on an average of 128 MMcf per day at an average price of US$3.82 per Mcf, representing approximately 47% of our forecasted natural gas production after royalties. For 2016, we have 25 MMcf per day, or 9% of our forecasted natural gas production after royalties, hedged through three-way collars with an average floor price of US$3.00 per Mcf.

Outlook

We delivered another quarter of strong operating results. On the back of this operational momentum and improved cost efficiencies, we are increasing our 2015 production guidance and reducing our operating and G&A expense guidance.

We continue to navigate through this challenging commodity price environment with a strong balance sheet and hedging program that will support our funds flow. We remain focused on driving improvement in our operational efficiencies through both reducing our cost structures and optimizing well performance.  Above all, the low commodity prices have not stopped us from committing the time and resources to ensure safe, responsible and sustainable operations across our business.

Q2 2015 Conference Call Details

A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00AM MT (11:00AM ET) today to discuss these results. Details of the conference call are as follows:

Date:	Friday, August 7, 2015
Time:	9:00 AM MT (11:00 AM ET)
Dial-In:	647-427-7450
	1-888-231-8191 (toll free)

Audiocast: http://event.on24.com/r.htm?e=1019901&s=1&k=5E5D391F544E5ABC6D1F186A4695576D

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 telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:

Dial-In:	416-849-0833
	1-855-859-2056 (toll free)
Passcode:	77813725

Electronic copies of our Second Quarter 2015 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 [email protected].

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.  

Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.

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", "ongoing", "may", "will", "project", "should", "believe", "plans", "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: expected 2015 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity and foreign exchange risk management programs in 2015 and in the future; expectations regarding our realized oil and natural gas prices; anticipated cash and non-cash G&A, share based compensation and financing expenses; operating and transportation costs; capital spending levels in 2015, anticipated drilling and completions program, and expected impact on our production level; potential future asset impairments; future debt and working capital levels and debt to funds flow ratio; our future acquisitions and dispositions; and the amount of future cash dividends that we may pay to our shareholders.

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; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments as needed; availability of third party services; and the extent of its liabilities. In addition, our 2015 revised guidance is based on the following assumptions: July 22, 2015 forward market WTI price of US$51.99 per barrel, NYMEX gas price of US$2.89 per Mcf, AECO gas price of $2.75 per GJ and USD/CDN exchange rate of 1.27. 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, including future decline, 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 Enerplus' capital spending activities or production declines; curtailment of Enerplus' production due to low realized prices or lack of adequate infrastructure; 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; our inability to comply with covenants under our bank credit facility and senior notes; changes in estimates 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; failure to complete any anticipated acquisitions or divestitures; 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 at December 31, 2014).

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 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" 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. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in our Second Quarter 2015 MD&A.

SOURCE Enerplus Corporation

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