May 5, 2017 - 6:00 AM EDT
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Enerplus Announces First Quarter 2017 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' First Quarter 2017 Financial Statements and MD&A are available on the Company's website at, under its SEDAR profile at and on the EDGAR website at

CALGARY, May 5, 2017 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its first quarter 2017 operating and financial results. The Company reported first quarter 2017 net income of $76.3 million, or $0.32 per share. This compares to a first quarter 2016 net loss of $173.7 million, or $0.84 per share.


  • Generated strong adjusted funds flow of $119.9 million
  • 24% operating netback improvement quarter-over-quarter
  • 18% improvement in realized Bakken differential, 32% improvement in realized Marcellus differential compared to the previous quarter 
  • Operating expenses of $6.59 per BOE, an 8% reduction quarter-over-quarter
  • Completed eight wells at Fort Berthold including three one-mile (short) lateral wells which had an average peak 30-day production rate per well of 1,528 BOE per day
  • On track to grow total Company liquids production by 25% from the first quarter of 2017 to the fourth quarter

"The rate of change in our financial metrics has been significant over the last twelve months," stated Ian C. Dundas, President and Chief Executive Officer. "We continued to focus our portfolio around high-margin, high rate-of-return assets, implement meaningful cost reductions across our business, and strengthen our financial position, while seeing structural improvements to our realized pricing in the Bakken and Marcellus. Our first quarter results demonstrate this step change in the cash flow generating capability and financial sustainability of our business."

"We are on track with the execution of our 2017 capital program to deliver strong oil volumes and cash flow growth and are well positioned to drive sustained, long-term profitable growth," Dundas added.


First quarter 2017 production averaged 84,937 BOE per day, including 36,336 barrels per day of crude oil and natural gas liquids. Total production was approximately 5% lower compared to the fourth quarter of 2016 due primarily to the divestment of non-operated North Dakota production in December 2016.

Subsequent to the quarter-end, Enerplus closed the final portion of the previously announced divestment of shallow gas assets in Canada, along with its Brooks waterflood property. The combined production associated with these divestments was approximately 7,300 BOE per day, of which 1,700 BOE per day closed during the first quarter, with the remaining 5,600 BOE per day having closed subsequent to the quarter-end.

Production in the Williston Basin began building momentum towards the end of the first quarter as the majority of wells completed during the quarter were brought on-stream in the latter half. Williston Basin production averaged 25,065 BOE per day during the quarter, with March production of approximately 27,000 BOE per day. Enerplus is well positioned to drive strong oil production growth through the year and achieve its fourth quarter total Company liquids production guidance of 43,000 to 48,000 barrels per day.

Enerplus generated first quarter 2017 adjusted funds flow of $119.9 million, an 11% increase from the previous quarter. The strong adjusted funds flow was a result of Enerplus' continued netback expansion from a combination of reductions to the Company's cost structure and improving realized pricing in the Bakken and Marcellus. Enerplus' first quarter 2017 operating netback, before hedging, was $17.99 per BOE, a 24% increase relative to the fourth quarter of 2016.

Enerplus' commodity hedging program realized cash gains of $6.6 million in the first quarter of 2017. The Company realized cash losses of $1.0 million on its crude oil contracts and cash gains of $7.6 million on its natural gas contracts, including unwinding a portion of its AECO-NYMEX basis physical contracts in connection with the previously announced sale of Canadian shallow gas properties.

Pricing dynamics in the Bakken and Marcellus have continued to improve with the buildout of pipeline infrastructure in both regions. Enerplus' realized Bakken crude oil price differential averaged US$5.59 per barrel below WTI in the first quarter of 2017, an 18% improvement relative to the previous quarter.  Enerplus' realized Marcellus natural gas sales price differential averaged US$0.60 per Mcf below NYMEX in the first quarter of 2017, a 32% improvement relative to the previous quarter.

Enerplus has continued to reduce its operating expenses through savings from divesting higher cost assets and continuing to optimize its operating processes. First quarter 2017 operating expenses averaged $6.59 per BOE, 8% lower compared to the prior quarter. As a result, Enerplus is lowering its 2017 operating expense guidance to $6.85 per BOE, from $7.25 per BOE. Enerplus expects operating costs to increase during the second half of 2017 as a result of the increasing liquids production and scheduled turnarounds in Canada.

Transportation costs in the first quarter of 2017 averaged $3.88 per BOE, an increase from $3.44 per BOE in the fourth quarter of 2016. The increase in transportation cost per BOE is primarily due to the divestment of non-operated North Dakota volumes at the end of 2016, and higher Marcellus production in the first quarter of 2017.

Cash G&A expenses were $1.87 per BOE in the first quarter of 2017, compared to $1.63 per BOE in the previous quarter. The increase in cash G&A expenses per BOE was largely due to the lower production volumes in the first quarter of 2017.

Enerplus remains in a strong financial position. Total debt net of cash and restricted cash at March 31, 2017 was $350.4 million. Total debt was comprised of $4.0 million drawn on the Company's $800 million bank credit facility, and $740.0 million of senior notes outstanding. Enerplus' cash balance was $393.6 million, including restricted cash. At March 31, 2017, Enerplus' net debt to adjusted funds flow ratio was 0.9 times.

Exploration and development capital spending in the first quarter of 2017 was $120.4 million, with $85.1 million directed to North Dakota, $25.1 million directed to the Canadian waterfloods, and $9.8 million directed to the Marcellus. Enerplus' 2017 exploration and development capital budget of $450 million is unchanged.


First Quarter 2017

Oil & NGL


Natural gas


Total Production


Williston Basin








Canadian Waterfloods(2)













Table may not add due to rounding.


First quarter production includes volumes from Canadian properties that were divested during and subsequent to the quarter-end.



First Quarter 2017


Non Operated





Williston Basin










Canadian Waterfloods












Williston Basin

Williston Basin production averaged 25,065 BOE per day (88% liquids) during the first quarter of 2017, a 22% decrease compared to the fourth quarter of 2016 largely due to the Company's divestment of non-operated North Dakota production in December 2016. First quarter Williston Basin production was comprised of 20,842 BOE per day in North Dakota and 4,223 BOE per day in Montana.

During the first quarter of 2017, Enerplus completed and brought on-stream eight gross operated wells (84% average working interest) at Fort Berthold. On the Elements pad, Enerplus completed a two-mile lateral Middle Bakken well that had a peak 30-day production rate of 1,723 BOE per day. On the Cactus pad, Enerplus completed four two-mile lateral wells (three Middle Bakken, one Three Forks) that had extended cleanout operations impacting initial production rates. The wells established an average peak 30-day production rate per well of 1,111 BOE per day. Enerplus completed three one-mile lateral wells (two Middle Bakken, one Three Forks) that had an average peak 30-day production rate per well of 1,528 BOE per day.  

Enerplus added a second operated drilling rig at Fort Berthold in January 2017. The Company drilled seven gross operated wells in the first quarter. Current gross Enerplus operated drilled and completed well costs for a two-mile lateral, assuming Enerplus' base completion design of 1,000 pounds of proppant per lateral foot, are US$6.7 million, with associated facilities costs of US$1.1 million per well.

Bakken price differentials have continued to strengthen over the past year due to regional production declines, strong regional demand, and the anticipated start-up of the Dakota Access Pipeline project in the second quarter of 2017. This project will result in regional pipeline capacity exceeding current production levels and is expected to support stronger Bakken prices going forward. Enerplus' realized Bakken crude oil price differential averaged US$5.59 per barrel below WTI in the first quarter of 2017, an 18% improvement relative to the fourth quarter of 2016. Enerplus continues to expect its Bakken crude oil differential to average approximately US$4.50 per barrel below WTI during 2017.


Marcellus production averaged 205 MMcf per day during the first quarter of 2017, a 7% increase compared to the previous quarter. Improving regional natural gas prices in the Marcellus have led to an increase in activity levels compared to 2016. Enerplus participated in nine gross non-operated wells (9% average working interest) that were brought on-stream during the first quarter of 2017. Six of these wells had more than 30 days on production as of the date of this news release with an average lateral length of 6,100 feet per well and an average peak 30-day production rate per well of 18.8 MMcf per day.

The Company participated in drilling 10 gross non-operated wells (17% average working interest) during the first quarter.

Enerplus' realized Marcellus sales price differential, excluding transportation and gathering, averaged US$0.60 per Mcf below NYMEX during the first quarter of 2017. Continued growth in regional natural gas power plant demand and the steady addition of new pipeline projects in 2016 has resulted in demand exceeding supply in the Northeast U.S. This has resulted in much stronger regional natural gas prices relative to prior periods. Enerplus estimates that the Northeast Pennsylvania region currently has excess egress pipeline capacity, and with additional infrastructure expected to be brought online over the next few years, Enerplus expects Marcellus price differentials will continue to remain strong in 2017 and improve further into 2018. As a result, Enerplus now expects its Marcellus natural gas realized price differential to average US$0.60 per Mcf below NYMEX during 2017.

Canadian Waterfloods

Canadian waterflood production averaged 16,438 BOE per day (79% liquids) during the first quarter of 2017, an increase of 4% from the previous quarter largely due to Ante Creek volumes which were acquired midway through the fourth quarter of 2016. First quarter volumes include production from the Brooks asset which was divested subsequent to the quarter-end. Excluding Brooks volumes, Canadian waterflood production averaged 13,570 BOE per day (80% liquids) during the first quarter.

Activity at Ante Creek was focused on expanding the supply of source water for injection, and optimizing facilities in preparation for increasing water injection. Other activity in the quarter was focused in Southeast Saskatchewan and at Cadogan where the Company drilled nine gross wells including two injector wells. The drilling programs were completed on time and budget with initial well results meeting or exceeding type curve expectations.


Enerplus continues to manage risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 18,680 barrels per day of crude oil protected for the remainder of 2017 (approximately 69% of forecast crude oil production net of royalties), 12,500 barrels per day of crude oil protected in 2018, and 4,000 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 net of royalties) using collar structures.

Commodity Hedging Detail (As at May 4, 2017)

WTI Crude Oil

Natural Gas


Apr 1, 2017 –
Jun 30, 2017

Jul 1, 2017 –
Dec 31, 2017

Jan 1, 2018 –
Dec 31, 2018

Jan 1, 2019 –
Mar 31, 2019

Apr 1, 2019 –
Dec 31, 2019

Apr 1, 2017 –
Dec 31, 2017


Sold Swaps







Volume (bbls/d or Mcf/d)







Three-Way Collars

Sold Puts







Volume (bbls/d or Mcf/d)







Purchased Puts







Volume (bbls/d or Mcf/d)







Sold Calls







Volume (bbls/d or Mcf/d)









Enerplus is reducing its 2017 operating expense guidance to $6.85 per BOE from $7.25 per BOE and narrowing its expected 2017 average Marcellus natural gas sales price differential to US$0.60 per Mcf below NYMEX from US$0.90 per Mcf below NYMEX. All other guidance is unchanged.


Capital spending

$450 million

Average annual production

81,000 – 85,000 BOE/d

Q4 average production

86,000 – 91,000 BOE/d

Average annual crude oil and natural gas liquids production

38,500 – 41,500 bbls/d

Q4 average crude oil and natural gas liquids production

43,000 – 48,000 bbls/d

Average royalty and production tax rate


Operating expense

$6.85 per BOE (from $7.25)

Transportation expense

$4.00 per BOE

Cash G&A expense

$1.85 per BOE


Differential/Basis Outlook(1)

2017 Average U.S. Bakken crude oil differential (compared to WTI crude oil):

US$(4.50) per bbl

2017 Average Marcellus natural gas sales price differential (compared to NYMEX natural gas):

US$(0.60) per Mcf (from US$0.90)


Excluding transportation costs.



A conference call hosted by Ian C. Dundas, President and CEO will be held at 8:00AM MT (10:00AM ET) today to discuss these results. Details of the conference call are as follows:


Friday, May 5, 2017


8:00 AM MT (10:00 AM ET)



1-888-231-8191 (toll free)



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:



1-855-859-2056 (toll free)





Three months ended March 31,



Financial (000's)

Adjusted Funds Flow(4)





Dividends to Shareholders



Net Income/(Loss)



Debt Outstanding – net of cash



Capital Spending



Property and Land Acquisitions



Property Divestments



Net Debt to Adjusted Funds Flow Ratio(4)



Financial per Weighted Average Shares Outstanding

Net Income/(Loss)





Weighted Average Number of Shares Outstanding (000's)



Selected Financial Results per BOE(1)(2)

Oil & Natural Gas Sales(3)





Royalties and Production Taxes



Commodity Derivative Instruments



Cash Operating Expenses



Transportation Costs



General and Administrative Expenses



Cash Share-Based Compensation



Interest, Foreign Exchange and Other Expenses



Current Income Tax Recovery/(Expense)



Adjusted Funds Flow(4)





Three months ended March 31, 



Average Daily Production(2)

Crude Oil (bbls/day)



Natural Gas Liquids (bbls/day)



Natural Gas (Mcf/day)



Total (BOE/day)



% Crude Oil and Natural Gas Liquids



Average Selling Price (2)(3)

Crude Oil (per bbl)





Natural Gas Liquids (per bbl)



Natural Gas (per Mcf)




Non‑cash amounts have been excluded.


Based on Company interest production volumes. See "Basis of Presentation" section in the MD&A.


Before transportation costs, royalties and commodity derivative instruments.


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 March 31, 

Average Benchmark Pricing



WTI crude oil (US$/bbl)





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



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



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



USD/CDN average exchange rate



Share Trading Summary

CDN(1) - ERF

U.S. (2) - ERF

For the three months ended March 31, 2017



















TSX and other Canadian trading data combined.


NYSE and other U.S. trading data combined.


2017 Dividends per Share



First Quarter Total






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 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.


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 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 risk management programs in 2017 and beyond; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2017 and its impact on our production level and land holdings; our 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 2017 guidance contained in this news release is based on the following: a WTI price of US$55.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.75/GJ and a USD/CDN exchange rate of 1.35. 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; 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 and Form 40-F at December 31, 2016).


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' First Quarter 2017 MD&A.

Electronic copies of Enerplus Corporation's First Quarter 2017 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at Shareholders may, upon request, receive a printed copy of our audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email [email protected].

Follow @EnerplusCorp on Twitter at

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

SOURCE Enerplus Corporation

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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 2017

Source: Canada Newswire (May 5, 2017 - 6:00 AM EDT)

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