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Enerplus Corporation

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Enerplus Announces Second Quarter 2019 Results
Enerplus Announces Second Quarter 2019 Results

Canada NewsWire

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 Enerplus' Second Quarter 2019 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.

CALGARY, Aug. 9, 2019 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported its second quarter 2019 operating and financial results. Cash flow from operating activities for the second quarter was $237.0 million and adjusted funds flow was $186.0 million. Second quarter net income was $85.1 million, or $0.36 per share, and adjusted net income was $74.3 million, or $0.32 per share.

HIGHLIGHTS

  • Second quarter total production was 100,694 BOE per day, up 14% quarter-over-quarter, exceeding the high-end of the Company's guidance
    • Liquids production was 52,861 barrels per day, up 16% quarter-over-quarter
    • North Dakota production was 43,822 BOE per day, up 22% quarter-over-quarter
  • 2019 total production guidance increased to 99,000 to 102,000 BOE per day (from 97,000 to 101,000 BOE per day) and liquids production guidance narrowed to 54,000 to 55,500 barrels per day (from 53,500 to 56,000 barrels per day)
    • 14% liquids production per share growth in 2019 at the guidance midpoint
  • 2019 capital spending guidance tightened to $610 to $630 million (from $590 to $630 million)
  • Returned approximately $115 million of capital to shareholders through dividends and share repurchases year to date
  • Based on current market conditions, Enerplus intends to repurchase its full authorization under its normal course issuer bid ("NCIB") equaling an additional 8.9 million shares as at August 7, 2019. Once completed, this would equate to a total of 24.2 million shares repurchased, or approximately 10% of shares outstanding, since initiating the share repurchase program in the third quarter of 2018
  • Improved 2019 Bakken oil differential guidance to US$3.25 per barrel below WTI (from US$4.00 per barrel)
  • Reduced 2019 unit cost guidance for operating expenses and cash general & administrative ("G&A") expenses
  • Maintained significant financial flexibility; total debt net of cash was $359.0 million with a net debt to adjusted funds flow ratio of 0.5 times

President and Chief Executive Officer Ian C. Dundas commented: "We've established strong operational momentum through the first half of the year and remain well positioned relative to our financial and operational targets in 2019. Our strategy continues to be underpinned by disciplined capital allocation which is delivering profitable oil production growth and return of capital to shareholders, while maintaining our peer-leading balance sheet strength."

"Since initiating our share repurchase program in the third quarter of 2018, we've returned over $175 million to shareholders through repurchases. Underlying this decision has been the compelling value we see in our equity. We continue to see this value in our shares today and remain committed to prioritizing the acquisition of our stock, based on current market conditions."

SECOND QUARTER FINANCIAL AND OPERATIONAL SUMMARY

Production
Production in the second quarter increased by 14% from the prior quarter to average 100,694 BOE per day, including oil and natural gas liquids production of 52,861 barrels per day (91% oil). The sequential production increase was driven by North Dakota and Marcellus volumes which were up 22% and 14%, respectively. With outperformance in the Marcellus and continued strong production in North Dakota, Enerplus is increasing its annual production guidance to 99,000 to 102,000 BOE per day (from 97,000 to 101,000 BOE per day) and narrowing its liquids production guidance to 54,000 to 55,500 barrels per day (from 53,500 to 56,000 barrels per day).

North Dakota production is expected to meaningfully build in the third quarter due to the timing of several well completions late in the second quarter and continued completions activity in the third quarter, with volumes moderating into the fourth quarter.

During the second quarter, Enerplus closed divestments for proceeds of $9.6 million primarily related to the sale of properties in southeast Saskatchewan with associated production of approximately 350 barrels per day (100% oil).

Adjusted Funds Flow and Adjusted Net Income
Second quarter 2019 adjusted funds flow was $186.0 million compared to $168.8 million in the previous quarter. Second quarter adjusted funds flow included a current tax recovery of $13.9 million. Second quarter 2019 adjusted net income was $74.3 million ($0.32 per share) compared to $72.5 million ($0.30 per share) in the previous quarter.

Pricing Realizations and Cost Structure
Enerplus' realized Bakken oil price differential averaged US$3.00 per barrel below WTI in the second quarter. Based on year to date price realizations and the continued strength in Bakken differentials, Enerplus is revising its full year Bakken differential guidance to US$3.25 per barrel below WTI (from US$4.00 per barrel). The Company continues to manage differential risk through fixed physical sales. For the second half of 2019, Enerplus has fixed physical differential sales of approximately 26,300 barrels per day of Bakken oil production at US$2.66 per barrel below WTI, including a portion which is sold directly into the U.S. Gulf Coast that utilizes the Company's firm capacity on the Dakota Access Pipeline. Enerplus' remaining production is sold through a combination of in-basin monthly spot and index sales.

The Company's realized Marcellus natural gas price differential moderated in the second quarter to US$0.57 per Mcf below NYMEX from the strong pricing in the prior quarter. A significant portion of the Company's Marcellus sales are tied to the Transco Zone 6 non-New York markets, where seasonal changes in demand drive prices lower from winter to spring. Enerplus is widening its full-year 2019 Marcellus differential guidance to US$0.35 per Mcf below NYMEX (from US$0.30 per Mcf).

Second quarter operating expenses were $7.84 per BOE, transportation expenses were $4.02 per BOE and cash G&A expenses were $1.26 per BOE. Enerplus is reducing its 2019 operating expense guidance to $7.90 per BOE (from $8.00 per BOE) and its cash G&A guidance to $1.45 per BOE (from $1.50 per BOE) primarily due to the Company's higher 2019 production expectations.

Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the second quarter was $207.2 million and was associated with drilling 12.7 net wells and bringing 26.3 net wells on production across the Company's operations. Enerplus has narrowed its 2019 capital spending guidance to $610 to $630 million (from $590 to $630 million) following the continued optimization of its operational plans. Capital spending for the second half of 2019 is expected to be weighted to the third quarter.

The Company continues to maintain its significant financial flexibility. At the end of the second quarter, its total debt net of cash was $359.0 million and its net debt to adjusted funds flow ratio was 0.5 times.

Share Repurchases
The Company repurchased and cancelled 6.6 million shares during the second quarter for total consideration of $70.6 million. Since initiating its share repurchase program in the third quarter of 2018 up to and including August 7, 2019, the Company has repurchased and cancelled 15.3 million shares for total consideration of $178 million

Enerplus continues to see the current trading value of its equity as discounted relative to the Company's internal view. As a result, the Company intends to repurchase the remaining authorization under its NCIB equaling an additional 8.9 million shares as at August 7, 2019. Combined with the shares repurchased to date, this would represent a total of 24.2 million shares repurchased, or approximately 10% of shares outstanding, since initiating its share repurchase program in the third quarter of 2018.  The Company's existing NCIB expires March 25, 2020.

ASSET ACTIVITY

Average Daily Production(1)


Three months ended
June 30, 2019


Six months ended
June 30, 2019


Crude Oil

(Mbbl/d)

Natural
Gas
Liquids
(Mbbl/d)

Natural gas

(MMcf/d)

Total
Production

(Mboe/d)


Crude Oil

(Mbbl/d)

Natural Gas
Liquids
(Mbbl/d)

Natural
gas

(MMcf/d)

Total
Production

(Mboe/d)

Williston Basin

38.8

3.7

26.6

46.9


35.1

3.5

25.9

42.9

Marcellus

-

-

237.3

39.5


-

-

223.2

37.2

Canadian Waterfloods

8.4

0.1

3.9

9.2


8.6

0.1

3.5

9.3

Other(2)

0.9

0.9

19.2

5.0


1.0

0.9

20.2

5.2

Total

48.1

4.7

287.0

100.7


44.6

4.6

272.9

94.7

(1)  Table may not add due to rounding.

(2)  Comprises DJ Basin and non-core properties in Canada.

 

Summary of Wells Brought On-Stream(1)


Three months ended
June 30, 2019


Six months ended
 June 30, 2019


Operated


Non-Operated


Operated


Non-Operated


Gross

Net


Gross

Net


Gross

Net


Gross

Net

Williston Basin

26

23.3


3

1.4


29

26.3


4

1.9

Marcellus

-

-


14

1.6


-

-


27

3.5

Canadian Waterfloods

-

-


-

-


1

1.0


-

-

Other(2)

-

-


-

-


-

-


2

0.5

Total

26

23.3


17

3.0


30

27.3


33

5.8

(1) Table may not add due to rounding.

(2) Comprises DJ Basin and non-core properties in Canada.

 

Williston Basin
Williston Basin production averaged 46,920 BOE per day (83% oil) during the second quarter of 2019, including 43,822 BOE per day from North Dakota (83% oil). The Company drilled 11 gross operated wells (73% average working interest) and brought 26 gross operated wells (90% average working interest) on production during the second quarter, including a nine-well pad at the end of June.

Enerplus continues to drive capital efficiency improvements with current well costs down approximately US$700,000 from 2018 levels driven by a combination of lower costs, efficiencies and completion optimization.  Enerplus' current total well cost for a two-mile lateral (drill, complete, tie-in and facilities) is estimated at US$7.5 million.

Marcellus
Marcellus production averaged 237 MMcf per day during the second quarter, 14% higher than the previous quarter. The Company participated in drilling eight gross non-operated wells (4% average working interest) and brought 14 gross non-operated wells (11% average working interest) on production during the quarter.

DJ Basin
The Company drilled five gross operated wells (88% average working interest) in the second quarter. These wells are expected to be completed in the third quarter.

2019 Guidance Updates

The Company's updated guidance for 2019 is in the table below, including changes from its previous guidance.

2019 Guidance

Capital spending

$610 to $630 million (from $590 to $630 million)

Average annual production

99,000 to 102,000 BOE/day (from 97,000 to 101,000 BOE/day)

Average annual crude oil and natural gas liquids production

54,000 to 55,500 bbls/day (from 53,500 to 56,000 bbls/d)

Average royalty and production tax rate

25%

Operating expense

$7.90/BOE (from $8.00/BOE)

Transportation expense

$4.00/BOE

Cash G&A expense

$1.45/BOE (from $1.50/BOE)

 

2019 Full-Year Differential/Basis Outlook (1)


U.S. Bakken crude oil differential (compared to WTI crude oil)

US$(3.25)/bbl (from US$(4.00)/bbl)

Marcellus natural gas sales price differential (compared to NYMEX natural gas)

US$(0.35)/Mcf (from US$(0.30)/Mcf)

(1)  Excluding transportation costs.

 

RISK MANAGEMENT

Enerplus continues to manage price risk through commodity hedging. Enerplus has an average of 24,500 barrels per day of crude oil protected for the remainder of 2019 and 16,000 barrels per day protected in 2020.

For natural gas, Enerplus has entered into offsetting swaps through October 31, 2019, effectively locking in gains of $0.51 per Mcf on the Company's original NYMEX hedges through this term.

Commodity Hedging Detail (As at August 7, 2019)






WTI Crude Oil
(US$/bbl)

NYMEX Natural Gas
(US$/Mcf)


Jul 1, – Sep 30,
2019

Oct 1, – Dec 31,
2019

Jan 1, – Dec 31,
2020

Jul 1 – Jul 31,

2019

Aug 1 – Oct 31,

2019

Swaps






Sold Swaps

-

-

-

$2.85

$2.85

Volume (bbls/d or Mcf/d)

-

-

-

90,000

90,000







Purchased Swaps

-

-

-

$2.34

$2.34

Volume (bbls/d or Mcf/d)

-

-

-

60,000

90,000







Three-Way Collars






Sold Puts

$44.64

$44.64

-

-

-

Volume (bbls/d or Mcf/d)

24,500

24,500

-

-

-







Purchased Puts

$54.81

$54.81

-

-

-

Volume (bbls/d or Mcf/d)

24,500

24,500

-

-

-







Sold Calls

$65.95

$65.99

-

-

-

Volume (bbls/d or Mcf/d)

24,500

24,500

-

-

-







Put Spreads






Sold Puts

-

-

$46.88

-

-

Volume (bbls/d or Mcf/d)

-

-

16,000

-

-







Purchased Puts

-

-

$57.50

-

-

Volume (bbls/d or Mcf/d)

-

-

16,000

-

-

(1)  The total average deferred premium on outstanding hedges is US$2.00/bbl from July 1, 2019 to December 31, 2020.

 

Q2 2019 Conference Call Details

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



Date:

Friday, August 9, 2019

Time:

9:00 AM MT (11:00 AM ET)

Dial-In:

587-880-2171 (Alberta)


1-888-390-0546 (Toll Free)

Conference ID:

18883249

Audiocast:   

https://event.on24.com/wcc/r/2040116/096536B9083B08C863107046B5B438D1

 

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:

Replay Dial-In:

1-888-390-0541 (Toll Free)

Replay Passcode:

883249 #

 

SELECTED FINANCIAL AND OPERATING RESULTS

SELECTED FINANCIAL RESULTS

Three months ended
June 30, 


Six months ended
June 30, 


2019


2018


2019


2018

Financial (000's)












Net Income

$

85,084


$

12,404


$

104,242


$

42,041

Cash Flow from Operating Activities


236,991



141,767



345,942



301,067

Adjusted Funds Flow(4)


186,038



173,708



354,793



328,870

Dividends to Shareholders - Declared


7,034



7,347



14,196



14,667

Total Debt Net of Cash(4)


359,006



311,782



359,006



311,782

Capital Spending


207,208



177,082



368,001



328,554

Property and Land Acquisitions


1,911



2,392



4,936



14,664

Property Divestments


9,601



(182)



10,067



6,788

Net Debt to Adjusted Funds Flow Ratio(4)


0.5x



0.5x



0.5x



0.5x













Financial per Weighted Average Shares Outstanding












Net Income - Basic

$

0.36


$

0.05


$

0.44


$

0.17

Net Income - Diluted


0.36



0.05



0.43



0.17

Weighted Average Number of Shares Outstanding (000's) - Basic


235,490



244,862



237,197



244,369

Weighted Average Number of Shares Outstanding (000's) - Diluted


238,189



250,122



239,947



249,367













Selected Financial Results per BOE(1)(2)












Oil & Natural Gas Sales(3)

$

44.00


$

48.13


$

44.33


$

45.65

Royalties and Production Taxes


(11.26)



(12.08)



(10.90)



(11.28)

Commodity Derivative Instruments


(0.13)



(2.28)



0.55



(0.57)

Cash Operating Expenses


(7.84)



(7.21)



(8.26)



(7.12)

Transportation Costs


(4.02)



(3.56)



(3.97)



(3.54)

Cash General and Administrative Expenses


(1.26)



(1.44)



(1.39)



(1.57)

Cash Share-Based Compensation


0.07



(0.05)



(0.04)



(0.16)

Interest, Foreign Exchange and Other Expenses


(0.79)



(0.95)



(0.75)



(0.99)

Current Income Tax Recovery/(Expense)


1.52



(0.01)



1.14



(0.01)

Adjusted Funds Flow(4)

$

20.29


$

20.55


$

20.71


$

20.41

SELECTED OPERATING RESULTS

Three months ended
June 30, 


Six months ended
June 30, 



2019



2018



2019



2018

Average Daily Production(2)












Crude Oil (bbls/day)


48,141



45,242



44,642



41,364

Natural Gas Liquids (bbls/day)


4,720



4,808



4,552



4,449

Natural Gas (Mcf/day)


287,000



256,995



272,863



259,141

Total (BOE/day)


100,694



92,883



94,671



89,003













% Crude Oil and Natural Gas Liquids


52%



54%



52%



51%













Average Selling Price (2)(3)












Crude Oil (per bbl)

$

74.42


$

79.98


$

70.82


$

75.34

Natural Gas Liquids (per bbl)


17.96



32.23



18.53



30.36

Natural Gas (per Mcf)


2.63



2.68



3.46



3.09













Net Wells Drilled


13



18



30



32

(1)

Non-cash amounts have been excluded.

(2)

Based on Company interest production volumes. See "Presentation of Production Information" below.

(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 this news release.

 


Three months ended
June 30, 


Six months ended
June 30, 

Average Benchmark Pricing

2019


2018


2019


2018

WTI crude oil (US$/bbl)

$

59.81


$

67.88


$

57.36


$

65.37

Brent (ICE) crude oil (US$/bbl)


68.32



74.90



66.11



71.04

NYMEX natural gas – last day (US$/Mcf)


2.64



2.80



2.89



2.90

USD/CDN average exchange rate


1.34



1.29



1.33



1.28







Share Trading Summary

CDN(1) - ERF


U.S.(2) - ERF

For the three months ended June 30, 2019

(CDN$)


(US$)

High

$

13.10


$

9.74

Low

$

8.76


$

6.53

Close

$

9.85


$

7.53

(1)  TSX and other Canadian trading data combined.

(2)  NYSE and other U.S. trading data combined.

 








2019 Dividends per Share


CDN$


US$(1)

First Quarter Total


$

0.03


$

0.02

Second Quarter Total



0.03


$

0.02

Total Year to Date


$

0.06


$

0.04

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

 

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 natural 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. To continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' 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.  

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", "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 2019 average production volumes, timing thereof 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 adjusted funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2019 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; expected operating and transportation costs; our anticipated shares repurchases under current and future normal course issuer bids; capital spending levels in 2019 and impact thereof on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; our future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; 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 we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. In addition, our updated 2019 guidance contained in this news release is based on the rest of the year prices of: a WTI price of US$56.00/bbl, a NYMEX price of US$2.30/Mcf, and a USD/CDN exchange rate of 1.31. 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: continued low commodity prices environment or further volatility 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; curtailment of our 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 our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent 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; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our Annual Information Form, our Annual MD&A and Form 40-F as at December 31, 2018). 

The forward-looking information contained in this news release speak only as of the date of this news release. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.

NON-GAAP MEASURES

In this news release, we use the terms "adjusted funds flow", "net debt to adjusted funds flow ratio" and "total debt net of cash" as measures to analyze operating performance, leverage and liquidity. "Adjusted funds flow" is calculated as cash flow generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and cash equivalents, divided by a trailing 12 months of adjusted funds flow. "Total debt net of cash" is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents. Calculation of these terms is described in Enerplus' MD&A under the "Non-GAAP Measures" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow", "net debt to adjusted funds flow", and "total debt net of cash" 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 Enerplus' Second Quarter 2019 MD&A.

Electronic copies of Enerplus Corporation's Second Quarter 2019 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of the Company's audited financial statements at any time. 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.

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

SOURCE Enerplus Corporation

View original content: http://www.newswire.ca/en/releases/archive/August2019/09/c4772.html

ENERPLUS CORPORATION, The Dome Tower, Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta T2P 2Z1, T. 403-298-2200 F. 403-298-2211, www.enerplus.comCopyright CNW Group 2019

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