Enerplus Announces Third Quarter 2017 Results

Nov 9, 2017

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' Third Quarter 2017 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, Nov. 9, 2017 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its third quarter 2017 operating and financial results. The Company reported third quarter 2017 net income of $16.1 million, or $0.07 per share. This compares to a third quarter 2016 net loss of $100.7 million, or $0.42 per share.

HIGHLIGHTS

  • On track to deliver full-year 2017 and fourth quarter liquids production targets
  • 2017 capital spending guidance unchanged at $450 million
  • Produced 33,300 BOE per day (85% oil) in October 2017 from North Dakota, up 60% since the first quarter of 2017
  • Ten wells brought on-stream in North Dakota during the third quarter with average peak 30-day production rates per well of 1,890 BOE per day, including the Smooth Green well with a peak 30-day production rate of 3,317 BOE per day
  • Realized Bakken differential below WTI averaged US$3.24 per barrel in the third quarter; expecting further improvement to US$2.00 per barrel in the fourth quarter
  • Generated adjusted funds flow of $90.4 million

"Our plan for 2017 remains on track and on budget to drive high-return crude oil production and associated cash flow growth from our top tier North Dakota position," stated Ian C. Dundas, President and Chief Executive Officer. "Our strategy of allocating capital to deliver sustainable, profitable cash flow growth continues to enhance our already strong financial position, giving us the flexibility and resiliency to continue to create long-term value for shareholders."

THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY

Third quarter 2017 production averaged 79,128 BOE per day, including 38,926 barrels per day of crude oil and natural gas liquids. Liquids production for the third quarter was 5% lower than the prior quarter primarily due to the divestment of the Brooks waterflood property which closed in the second quarter, and a completions program in North Dakota weighted to the end of the quarter (approximately 70% of third quarter net completions occurred in September). The Company is on track to drive strong fourth quarter oil volumes with North Dakota production in October averaging 33,300 BOE per day (85% oil), compared to 27,210 BOE per day in the third quarter. Total Company liquids production in October averaged 44,600 barrels per day.

Enerplus remains well positioned relative to its full-year 2017 and fourth quarter liquids production targets. The Company has updated its full-year 2017 liquids production guidance to 40,500 barrels per day (from 39,500 to 41,500 barrels per day) and narrowed its fourth quarter liquids production guidance range to 45,000 to 46,000 barrels per day (from 43,000 to 48,000 barrels per day).

Natural gas production for the third quarter averaged 241 MMcf per day, 11% lower than the prior quarter primarily due to the divestment of Canadian shallow gas properties which closed in the second quarter, and price related production curtailments in the Marcellus during September. Enerplus curtailed approximately 25 MMcf per day of its Marcellus natural gas production during September and approximately 35 MMcf per day in October due to unfavourable prices in the daily cash market. Since early November, regional pricing has improved and the Company has returned to producing at an unrestricted rate of approximately 200 MMcf per day in the Marcellus. Although Enerplus anticipates stronger Marcellus pricing in November and December, the Company remains committed to focusing on value and therefore there may be further curtailment in the event prices weaken during the remainder of the fourth quarter.

As a result of the Marcellus curtailments in September and October, Enerplus has revised its total annual average production guidance for 2017 to 84,000 BOE per day (from 84,000 to 86,000 BOE per day) and its fourth quarter production guidance range to 86,000 to 88,000 BOE per day (from 86,000 to 91,000 BOE per day). This guidance assumes no further Marcellus production curtailments in the fourth quarter. Total Company production in October averaged 82,700 BOE per day.

Enerplus generated adjusted funds flow of $90.4 million in the third quarter, compared to $114.2 million in the previous quarter. The quarter-over-quarter reduction was primarily due to wider natural gas differentials and the strengthening of the Canadian dollar in the third quarter. Tighter Bakken differentials and lower transportation costs in the third quarter partially offset the reduction in adjusted funds flow.

Exploration and development capital spending in the third quarter was $119.1 million associated with drilling, completing, and bringing 10.3 net wells on production. The Company's 2017 exploration and development capital budget of $450 million is unchanged.

Enerplus' realized Bakken crude oil price differential averaged US$3.24 per barrel below WTI in the third quarter, an improvement of US$2.19 per barrel relative to the previous quarter. Spot Bakken prices strengthened considerably throughout the quarter due to the improved egress capacity from the Bakken, on-going Canadian synthetic supply outages, and incremental demand from refineries for light barrels due to on-going market disruption during an active hurricane season. Accordingly, Enerplus is narrowing its expected realized Bakken differential to US$2.00 per barrel below WTI for the fourth quarter and its full-year differential to approximately US$4.00 per barrel below WTI.

Enerplus' realized Marcellus natural gas sales price differential widened to US$1.02 per Mcf below NYMEX in the third quarter compared to US$0.64 per Mcf below NYMEX in the previous quarter. Enerplus' transportation and sales contracts and its fixed basis hedges moderated the weakness as the benchmark monthly Transco Leidy price widened to average US$1.29 per Mcf below NYMEX during the quarter. Marcellus pricing weakened during the quarter due to cooler than average weather in the northeast United States combined with incremental supply coming on-stream during the quarter in expectation of flowing on the subsequently delayed Rover Pipeline. Additional Marcellus pipeline capacity is being brought on-line during the fourth quarter of 2017, including partial capacity of Rover, which is expected to be at full capacity towards the end of the first quarter of 2018. Although pricing strengthened in early November, Marcellus pricing remained weak in October with Transco Leidy daily prices averaging US$0.76 per Mcf. Enerplus is widening its full year 2017 Marcellus realized differential guidance to US$0.80 per Mcf below NYMEX (from US$0.75 per Mcf), and estimates its fourth quarter realized differential will average approximately US$1.05 per Mcf below NYMEX.

Third quarter operating expenses averaged $6.71 per BOE, 15% higher compared to the prior quarter. Operating expenses increased in the third quarter primarily due to lower Marcellus production relative to the previous quarter and higher gas facility charges and well servicing costs on the Company's oil properties. As a result of the impact of the Marcellus curtailment in September and October, Enerplus is increasing its full-year 2017 operating expenses to $6.50 per BOE, from $6.40 per BOE. This increase to operating expense guidance is more than offset by reductions in per BOE transportation and cash G&A guidance, noted below.

Transportation costs in the third quarter averaged $3.61 per BOE, a decrease from $3.72 per BOE in the second quarter of 2017. Transportation costs decreased in the third quarter due to lower Marcellus production relative to the previous quarter and a stronger Canadian dollar. Enerplus is reducing its 2017 guidance for transportation costs to $3.70 per BOE, from $3.90 per BOE.

Cash G&A expenses were $1.61 per BOE for the quarter, compared to $1.53 per BOE in the previous quarter. The modest increase in cash G&A on a BOE basis was due to lower production volumes relative to the previous quarter. Total cash G&A of approximately $11.7 million was broadly flat to the prior quarter. Enerplus is reducing its cash G&A expense guidance to $1.70 per BOE from $1.75 per BOE.

Enerplus remains in a strong financial position. Total debt net of cash at September 30, 2017 was $318.3 million. Total debt was comprised of $667.3 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility, and had a cash balance of $349.0 million. At September 30, 2017, Enerplus' net debt to adjusted funds flow ratio was 0.7 times.

AVERAGE DAILY PRODUCTION(1)


Three months ended September 30,
2017


Nine months ended September 30,
2017


Oil & NGL

(Mbbl/d)

Natural gas

(MMcf/d)

Total
Production

(Mboe/d)


Oil & NGL

(Mbbl/d)

Natural gas

(MMcf/d)

Total
Production

(Mboe/d)

Williston Basin

28.0

18.7

31.0


26.4

19.0

29.5

Marcellus

0.0

189.7

31.6


0.0

199.6

33.3

Canadian Waterfloods(2)

10.1

8.7

11.6


11.4

14.1

13.7

Other(2)

0.8

24.2

4.9


1.1

35.1

6.9

Total

38.9

241.2

79.1


38.8

267.9

83.4

(1)

Table may not add due to rounding.

(2)

Nine month figures include volumes from Canadian properties that were divested during the first six months of 2017.

 

SUMMARY OF WELLS BROUGHT ON-STREAM(1)


Three months ended September 30,
2017


Nine months ended September 30,
2017


Operated


Non Operated


Operated


Non Operated


Gross

Net


Gross

Net


Gross

Net


Gross

Net

Williston Basin

10

8.6


1

0.0


29

23.4


2

0.5

Marcellus

0

0.0


15

0.7


0

0.0


42

3.8

Canadian Waterfloods

0

0.0


0

0.0


6

6.0


0

0.0

Other

1

1.0


0

0.0


1

1.0


0

0.0

Total

11

9.6


16

0.7


36

30.4


44

4.3

(1)

Table may not add due to rounding.

 

ASSET ACTIVITY

Williston Basin

Williston Basin production averaged 30,981 BOE per day (90% liquids) during the third quarter of 2017, 4% lower than the second quarter. This decrease was expected due to a completions program in North Dakota weighted to the end of the third quarter, in part a function of pad development. Third quarter Williston Basin production was comprised of 27,210 BOE per day in North Dakota and 3,771 BOE per day in Montana. 

In the third quarter, Enerplus brought on-stream 10 gross operated wells (86% average working interest) across its acreage at Fort Berthold with an average completed lateral length of 8,770 feet per well and average peak 30-day production rates per well of 1,890 BOE per day (77% oil, on a three-stream basis). Of note are four-wells on the Snakes pad, located in the northwest of Enerplus' Fort Berthold acreage position, a high productivity area. The four wells had an average completed lateral length per well of 9,100 feet and average peak 30-day production rates per well of 2,185 BOE per day (75% oil). The average proppant loading across the 10 operated completions in the quarter was 1,250 pounds per foot, including two wells, Smooth Green (Snakes pad) and Crane (Cranes pad), testing 2,000 pounds per foot. The Smooth Green and Crane wells had peak 30-day production rates of 3,317 BOE per day (75% oil) and 1,950 BOE per day (83% oil) respectively.

The Company drilled 10 gross operated wells (66% average working interest) in the third quarter.

The strong 2017 production growth from North Dakota is set to continue in the fourth quarter with October production from North Dakota averaging 33,300 BOE per day (85% oil).

Marcellus

Marcellus production averaged 190 MMcf per day during the third quarter, a reduction of 7% from the previous quarter primarily due to price related curtailments of approximately 25 MMcf per day during September. Fifteen gross non-operated wells (5% average working interest) were brought on-stream during the quarter with an average completed lateral length of 6,300 feet per well and average peak 30-day production rates per well of 14.8 MMcf per day.

The Company participated in drilling 19 gross non-operated wells (12% average working interest) during the third quarter.

Enerplus continued to curtail approximately 35 MMcf per day of its Marcellus production in October due to unfavourable prices in the daily cash market. Since early November, regional pricing has improved and the Company has returned to producing at an unrestricted rate of approximately 200 MMcf per day.  

Canadian Waterfloods

Canadian waterflood production averaged 11,588 BOE per day (87% liquids) during the third quarter, a decrease of 12% from the previous quarter primarily due to the divestment of the Brooks property during the second quarter. Activity in the quarter was largely focused on waterflood optimization and the continued advancement of waterflood implementation at Ante Creek, where total water injection has increased to 9,000 barrels of water per day, with a target injection of approximately 12,000 barrels of water per day by year-end.

2017 UPDATED GUIDANCE

Enerplus' updated 2017 guidance is summarized below.




Guidance

Capital spending

$450 million

Average annual production

84,000 BOE/d (from 84,000 – 86,000 BOE/d)

Q4 average production

86,000 – 88,000 BOE/d (from 86,000 – 91,000 BOE/d)

Average annual crude oil and natural gas liquids production

40,500 bbls/d (from 39,500 – 41,500 bbls/d)

Q4 average crude oil and natural gas liquids production

45,000 – 46,000 bbls/d (from 43,000 – 48,000 bbls/d)

Average royalty and production tax rate

24%

Operating expense

$6.50/BOE (from $6.40/BOE)

Transportation expense

$3.70/BOE (from $3.90/BOE)

Cash G&A expense

$1.70/BOE (from $1.75/BOE)

 

2017 Differential/Basis Outlook (1)


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

US$(4.00)/bbl (from US$(4.50)/bbl)

Q4 Average U.S. Bakken crude oil differential (compared to WTI crude oil):

US$(2.00)/bbl

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

US$(0.80)/Mcf (from US$(0.75)/Mcf)

Q4 Average Marcellus natural gas sales price differential (compared to NYMEX natural gas):

US$(1.05)/Mcf

(1)  Excluding transportation costs.


 

RISK MANAGEMENT

Enerplus continues to manage price risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 20,000 barrels per day of crude oil protected for the remainder of 2017 (approximately 72% of forecast crude oil production at the midpoint of annual average guidance, net of royalties), approximately 19,500 barrels per day of crude oil protected in 2018, and 10,000 barrels per day of crude oil protected in 2019.

For natural gas, Enerplus has 50,000 Mcf per day protected for the remainder of 2017 (approximately 25% of forecast natural gas production at the midpoint of annual average guidance, net of royalties) using collar structures. For 2018, Enerplus has 25,000 Mcf per day protected using collar structures.

Commodity Hedging Detail (As at November 8, 2017)


WTI Crude Oil
(US$/bbl) (1)

Nymex Natural Gas
(US$/Mcf) (1)


Oct 1, –
Dec 31,
2017

Jan 1, –
Mar 31,
2018

Apr 1 –
Jun 30,
2018

Jul 1 –
Sep 30,
2018

Oct 1 –
Dec 31,
2018

Jan 1, –
Mar 31,
2019

Apr 1, –
Dec 31,
2019

Oct 1, 2017 –

Dec 31, 2017

Jan 1, 2018 –

Dec 31, 2018











Swaps










Sold Swaps

$53.50

$53.73

$53.73

$53.73

$53.73

$53.73

-

-

-

Volume (bbls/d or Mcf/d)

2,000

3,000

3,000

3,000

3,000

3,000

-

-

-











Three-Way Collars










Sold Puts

$39.62

$42.83

$42.92

$42.71

$42.74

$43.54

$43.48

$2.06

-

Volume (bbls/d or Mcf/d)

18,000

13,000

15,000

18,000

20,000

7,000

10,000

50,000

-











Purchased Puts

$50.61

$53.04

$52.90

$52.53

$52.48

$53.21

$53.53

$2.75

$2.75

Volume (bbls/d or Mcf/d)

18,000

13,000

15,000

18,000

20,000

7,000

10,000

50,000

25,000











Sold Calls

$60.33

$61.99

$61.73

$61.22

$61.10

$61.14

$62.27

$3.41

$3.46

Volume (bbls/d or Mcf/d)

18,000

13,000

15,000

18,000

20,000

7,000

10,000

50,000

25,000

(1)

  Based on weighted average price (before premiums). A portion of the sold puts are settled annually rather than monthly.

 

Q3 2017 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:

Thursday, November 9, 2017

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=1516988&s=1&k=20AE8FC7B0697879EF594B0CE2E9A824

 

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:

92669366

 

SELECTED FINANCIAL AND OPERATING RESULTS


Three months ended
September 30,


Nine months ended
September 30, 


2017


2016


2017


2016

Financial (000's)












Net Income/(Loss)

$

16,131


$

(100,689)


$

221,726


$

(442,909)

Adjusted Funds Flow(4)


90,386



80,101



324,505



197,875

Dividends to Shareholders


7,264



7,214



21,769



28,225

Debt Outstanding – net of Cash


318,273



654,071



318,273



654,071

Capital Spending


119,102



60,277



341,188



151,673

Property and Land Acquisitions


2,222



3,777



9,471



7,674

Property Divestments


(1,361)



111



57,581



280,614

Net Debt to Adjusted Funds Flow Ratio(4)


0.7x



2.2x



0.7x



2.2x













Financial per Weighted Average Shares Outstanding












Net Income/(Loss)

$

0.07


$

(0.42)


$

0.92


$

(2.00)

Weighted Average Number of Shares Outstanding (000's)


242,129



240,483



241,854



221,843













Selected Financial Results per BOE(1)(2)












Oil & Natural Gas Sales(3)

$

33.23


$

27.20


$

35.21


$

23.69

Royalties and Production Taxes


(7.98)



(6.20)



(8.28)



(5.20)

Commodity Derivative Instruments


0.40



1.17



0.51



2.75

Cash Operating Expenses


(6.73)



(6.64)



(6.39)



(7.33)

Transportation Costs


(3.61)



(3.39)



(3.74)



(3.05)

Cash General and Administrative Expenses


(1.61)



(1.58)



(1.67)



(1.79)

Cash Share-Based Compensation


(0.10)



(0.03)



(0.04)



(0.07)

Interest, Foreign Exchange and Other Expenses


(1.17)



(1.07)



(1.25)



(1.37)

Current Income Tax Recovery/(Expense)


(0.01)



(0.01)



(0.10)



0.01

Adjusted Funds Flow(4)

$

12.42


$

9.45


$

14.25


$

7.64

 


Three months ended September 30, 


Nine months ended September 30, 


2017


2016


2017


2016

Average Daily Production(2)












Crude Oil (bbls/day)


35,245



37,717



35,102



38,764

Natural Gas Liquids (bbls/day)


3,681



4,881



3,659



5,067

Natural Gas (Mcf/day)


241,212



296,876



267,852



304,150

Total (BOE/day)


79,128



92,077



83,403



94,523













% Crude Oil and Natural Gas Liquids


49%



46%



46%



46%













Average Selling Price (2)(3)












Crude Oil (per bbl)

$

54.21


$

47.93


$

55.75


$

41.92

Natural Gas Liquids (per bbl)


26.22



13.85



29.09



13.53

Natural Gas (per Mcf)


2.58



2.12



3.26



1.79

(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 September 30, 


Nine months ended September 30, 

Average Benchmark Pricing

2017

2016


2017

2016

WTI crude oil (US$/bbl)

$

48.20

$

44.94


$

49.47

$

41.33

AECO natural gas– monthly index (CDN$/Mcf)


2.04


2.20



2.58


1.85

AECO natural gas – daily index (CDN$/Mcf)


1.45


2.32



2.31


1.85

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


3.00


2.81



3.17


2.29

USD/CDN average exchange rate


1.25


1.31



1.31


1.32

 

Share Trading Summary

CDN (1) - ERF

U.S. (2) - ERF

For the three months ended September 30, 2017

(CDN$)

(US$)

High

$

12.58

$

10.21

Low

$

9.75

$

7.55

Close

$

12.31

$

9.87

(1)  TSX and other Canadian trading data combined.





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





 

2017 Dividends per Share

CDN$


US$(1)

First Quarter Total

$

0.03


$

0.02

Second Quarter Total

$

0.03


$

0.02

Third Quarter Total

$

0.03


$

0.02

Total Year to Date

$

0.09


$

0.06

(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. In order 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.  

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  average production volumes in 2017 and the anticipated production mix; the portion of Marcellus production that is curtailed; the proportion of anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting funds flow; the results from the drilling program and the timing of related production; oil and natural gas prices and differentials and  commodity risk management programs in 2017, 2018, and beyond; expectations regarding realized oil and natural gas prices; future royalty rates on production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2017 and its impact on production levels and land holdings; future royalty and production and cash taxes; future debt and working capital levels and debt to funds flow ratios.

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 updated 2017 guidance contained in this news release is based on the following prices for the rest of the year: a WTI price of US$50.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.00/GJ and a USD/CDN exchange rate of 1.28. 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 continued volatility, 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; Enerplus' inability to comply with covenants under its 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 its Annual Information Form, management's discussion and analysis for the year-ended December 31, 2016, and Form 40-F at December 31, 2016).

The forward-looking information contained in this press release speak only as of the date of this press 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" and "net debt to adjusted funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Adjusted 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. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and restricted cash, divided by a trailing 12 months of adjusted funds flow. Calculation of these terms is described in Enerplus' MD&A under the "Liquidity and Capital Resources" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow" and "net debt to adjusted 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 Enerplus' Third Quarter 2017 MD&A.

Electronic copies of Enerplus Corporation's Third Quarter 2017 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

For further information: 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.com


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Last Updated: April 29th, 2014
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