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Enerplus to Acquire Strategic Williston Basin Assets, Updates 2021 Guidance and Provides Five Year Outlook

April 8, 2021

CALGARY, AB, April 8, 2021 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today announced that it has entered into a definitive agreement to acquire assets in the Williston Basin from Hess Corporation for total cash consideration of US$312 million (the "Acquisition"). In connection with the Acquisition, the Company has updated its 2021 guidance including an increased production outlook due to operational outperformance year to date. The Company has also provided a five-year outlook based on principles of maintaining low financial leverage, generating meaningful free cash flow and returning capital to shareholders.

Enerplus Williston Basin Map April 2021 Acquisition (CNW Group/Enerplus Corporation)


  • Core acreage with substantial high-return drilling inventory – Acquiring 78,700 largely contiguous net acres in Dunn County, North Dakota, strategically adjacent to Enerplus' core Bakken position. The Acquisition includes 110 net tier one undrilled locations (77% operated) which immediately compete for capital with Enerplus' existing locations. The Acquisition is accretive to Enerplus' drilling inventory, extending its development drilling by an additional two to three years based on these tier one locations. After the Acquisition, Enerplus estimates it will have approximately 10 years of drilling inventory under mid-single digit annual liquids production growth rates. In addition to these tier one locations, the Acquisition includes 120 net operated undrilled locations which are economic based on current crude oil prices, and which offer the potential for more compelling returns with the application of modern stimulation and production technologies.
  • Significant potential in undeveloped acreage evidenced by active proximal development – Unique opportunity in an extensive, largely undeveloped core position. The acreage is 100% held by production with an average of two producing wells per drilling spacing unit. Recent development by offset operators deploying modern stimulation designs (high proppant and fluid intensity) has delivered strong well results in both the Middle Bakken and Three Forks formations. The total 230 net undrilled inventory locations referenced above are almost exclusively focused in the Middle Bakken formation; additional development potential exists beyond this in the Three Forks formation. In addition, the acquired acreage has very limited exposure to federal land (less than 3% of the total net acreage).
  • Low decline base production – The Acquisition includes approximately 6,000 BOE per day (76% tight oil, 10% natural gas liquids ("NGL") and 14% natural gas) of working interest(1) production (estimated at the time of closing), with a base decline rate under 20% (10% on the operated production, 37% on the non-operated production). An independent reserves report on the properties, prepared by McDaniel & Associates, effective as of March 1, 2021 has assigned proved plus probable reserves of 62.7 MMBOE consisting of 49.7 MMbbls of tight oil, 7.1 MMbbls of NGL and 35.1 Bcf of shale gas (working interest(1)).
  • Meaningful near-term accretion – Expected to be accretive to per share metrics in the first year, including adjusted funds flow, free cash flow and net asset value. Accretion levels are expected to increase after the first year with adjusted funds flow per share and free cash flow per share accretion expected to be 13% and 7%, respectively, by the end of 2022, increasing to approximately 20% for each metric by the end of 2024 based on the Company's five year outlook outlined below and assuming a US$55 per barrel WTI crude oil price.(2)  
  • Acquisition contributes to free cash flow outlook – The acquired assets are expected to consistently generate free cash flow. Planned development is estimated to be self-funded in-line with an annual capital spending reinvestment rate of approximately 60% to 70% of adjusted funds flow assuming a US$50 to $55 WTI crude oil price. The Acquisition and Enerplus' production outperformance are expected to increase the Company's free cash flow generation in 2021, which is now estimated at over $330 million, based on a US$55 per barrel WTI crude oil price.(2)
  • Balance sheet remains strong – The pro forma business retains a solid financial position with an estimated net debt to adjusted funds flow ratio at or below 1.3x at December 31, 2021 (annualized for 2021 acquisitions), reducing to approximately 1.0x or less by year-end 2022 based on a US$55 per barrel WTI crude oil price.(2) Enerplus will continue to have ample liquidity and maintain significant financial flexibility subsequent to the Acquisition and anticipates increasing the size of its bank credit facility up to US$900 million prior to the Acquisition closing.
  • Drives continued operational synergies – The Acquisition is expected to support a more efficient capital and operating plan through more consistent activity levels and high-graded development. In addition, there are no incremental general and administrative costs associated with the Acquisition.

"These assets are a strong strategic and operational fit for Enerplus, further extending our high-return Bakken drilling inventory," said Ian C. Dundas, President and CEO of Enerplus. "The addition of this tier one resource into our development plan is expected to generate strong financial returns and enhance our free cash flow growth. In connection with the acquisition, we have highlighted a five-year outlook with projected cumulative free cash flow of between $1.2 to $1.8 billion between 2021 and 2025, assuming US$50 to $55 per barrel WTI."


Enerplus has agreed to acquire the properties for total cash consideration of US$312 million pursuant to a purchase and sale agreement, subject to customary purchase price adjustments. The Acquisition will be funded with the Company's existing cash position of approximately US$150 million with the remaining portion funded through borrowing on its undrawn bank credit facility. Closing of the Acquisition is subject to customary closing conditions and is expected to occur in May 2021.


Enerplus is increasing its 2021 production guidance to 111,000 to 115,000 BOE per day (from 103,500 to 108,500 BOE per day), including 68,500 to 71,500 barrels per day of liquids (from 63,000 to 67,000 barrels per day) based on an eight month contribution from the Acquisition to the Company's 2021 production. The increased production guidance was also driven by strong operating performance in North Dakota and higher than expected production in the Marcellus through the first three months of the year. Capital spending in 2021 is revised to $360 to $400 million (from $335 to $385 million) in connection with the acquired assets.

The Company's 2021 Bakken oil price differential outlook is unchanged at $3.25 per barrel below WTI, which assumes the Dakota Access Pipeline ("DAPL") continues to operate. In the event DAPL is required to cease operations, Enerplus expects sufficient rail egress to be available, however, Bakken oil price differentials would be expected to widen reflecting rail economics. The Company estimates this would result in a realized 2021 differential of approximately $6.00 per barrel below WTI, assuming eight months of wider differentials if DAPL cannot operate. The impact to Enerplus' corporate netback in this scenario is estimated to be approximately $0.90 per BOE. The Acquisition is expected to continue to provide attractive financial returns at a wider differential, as outlined above.


Enerplus 2021 Previous

Pro Forma 2021 Guidance
(based on an eight-month
contribution from the Acquisition)

Increase to the
Guidance Midpoint

Total production (BOE/d)(1)

103,500 to 108,500

111,000 to 115,000


Liquids production (bbl/d)(1)

63,000 to 67,000

68,500 to 71,500


Capital spending ($MM)

$335 to $385

$360 to $400


(1) Production is stated on a working interest basis before the deduction of royalties.


In connection with its five-year outlook, Enerplus has provided a capital allocation framework with the following key principles:

  • Maintain low financial leverage: Target a long-term net debt to adjusted funds flow ratio of less than 1.0x.
  • Committed to free cash flow generation: Target a long-term capital spending reinvestment rate of less than 75% of annual adjusted funds flow.
  • Return capital to shareholders: Sustainably grow the Company's base dividend supported by an increasing cash flow base. Consider share repurchases to further enhance the return of capital to shareholders.

The key principles above and the macro environment will drive Enerplus' disciplined approach to growth, maximizing free cash flow and shareholder returns.

To highlight Enerplus' financial sustainability and robust free cash flow growth potential, the Company has provided an outlook through 2025. Assuming a constructive commodity price environment (WTI oil prices at approximately US$50 to $55 per barrel or higher), the Company projects annual capital spending of approximately $500 million from 2022 to 2025 focused on generating substantial levels of free cash flow. Under this capital spending plan, cumulative free cash flow is estimated at $1.2 to $1.8 billion between 2021 and 2025 based on a US$50 to $55 per barrel WTI crude oil price and US$2.75 per Mcf NYMEX natural gas price.(2)  This is expected to result in an average capital spending reinvestment rate of approximately 60% to 70% of adjusted funds flow over the period. Enerplus projects 3% to 5% annual liquids production growth from 2022 to 2025 based on this outlook. This growth rate is based on approximately 75,000 barrels per day, being the Company's implied liquids production in 2021 assuming a full year contribution from its recent acquisitions.


Stifel FirstEnergy acted as financial advisor, BMO Capital Markets acted as strategic advisor. Vinson & Elkins LLP acted as U.S. legal advisor and Blake, Cassels & Graydon LLP acted as Canadian legal advisor to Enerplus on the Acquisition.


An investor presentation in connection with the Acquisition has been added to the Company's website at


(1) Production and reserves are stated on a working interest basis before deduction of royalties.
(2) Assumes NYMEX natural gas prices of US$3.00 per Mcf in 2021 and US$2.75 per Mcf in 2022 and thereafter.


Enerplus is an independent North American oil and gas exploration and production company focused on creating long-term value for its shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations.

Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified.

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 and Reserves 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 required to be presented on a gross basis before deduction of royalties. In order to continue to be comparable with its Canadian peer companies, unless otherwise stated, the information contained within this news release presents Enerplus' production and BOE measures on a before royalty "company interest" basis. All production volumes presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest. This news release also contains references to the percentage of the Company's production that is hedged under commodity derivatives contracts, this percentage being based upon the Company's net of royalty production volumes. All reserves volumes in this news release (and all information derived therefrom) are based on "gross reserves" using forecast prices and costs. "Gross reserves" (as defined in NI 51-101), are Enerplus' working interest before deduction of any royalties. Information about reserves on the properties contained in this press release is derived from a report on the properties effective as of March 1, 2021 prepared by McDaniel & Associates Ltd., an independent reserves evaluator. The drilling locations identified in this news release are comprised of 153 gross (66.1 net) proved plus probable undeveloped reserves locations identified by McDaniel & Associates Ltd, 166 gross (44.5 net) unbooked future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators and considered highly economic, and 155 gross (120.7 net) unbooked future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators as offering future development potential but with more marginal economics based on the current assessment.

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: anticipated completion of the Acquisition, including expected purchase price, terms, timing and completion thereof; expected benefits of the Acquisition; expected impacted of the Acquisition on Enerplus' operations and financial results, including inventory of drilling locations, expected accretion to Enerplus' metrics (including expected free cash flow in 2021 and beyond and year-end net debt to adjusted funds flow ratio); Enerplus' expected 2021 average production volumes and expected capital levels to support such production; anticipated production mix and Enerplus' expected source of funding thereof; expected operating plans; oil and natural gas prices and differentials; anticipated impact of the Acquisition on Enerplus' future costs and expenses; expected increase in the size of Enerplus' credit facility; Enerplus' five year outlook, including expected capital spending levels and resulting production, production growth and free cash flow, and plans for excess cash flow, including potential share repurchases.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that the Acquisition will be completed substantially on the terms and within the timeline described in this press release; that Enerplus will realize expected benefits of the Acquisition described in this press release and of its prior acquisition of Bruin E&P HoldCo, LLP (the "Bruin Acquisition") as previously announced; 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, including expectations regarding the duration and overall impact of COVID-19; 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, Enerplus' updated 2021 outlook contained in this news release is based on the following: a WTI price of between US$55.00/bbl, a NYMEX price of US$3.00/Mcf, a Bakken crude oil price differential of US$3.25/bbl below WTI and a USD/CDN exchange rate of 1.27. Furthermore, in addition, Enerplus' five-year outlook contained in this news release is based on the following: a WTI price of between US$50.00/bbl and US$55.00/bbl, a NYMEX price of US$3.00/Mcf in 2021 and US$2.75/Mcf thereafter, a Bakken crude oil price differential of US$3.25/bbl below WTI in 2021 and US$2/bbl to US$3/bbl below WTI thereafter and a 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: failure to complete the Acquisition, at all or on terms or within the timeline described in this press release; failure by Enerplus to realize anticipated benefits of the Acquisition or the Bruin Acquisition; changes, including future decline, in commodity prices, including as a result of continued COVID-19 pandemic; changes in realized prices for Enerplus' products from those currently anticipated; 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; 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; changes in law or government programs or policies in Canada or the United States; 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 for the year ended December 31, 2020, management's discussion and analysis ("MD&A"), and Form 40-F at December 31, 2020 as it may be updated from time to time by current reports on Form 6-K, all of which are available, as applicable, on SEDAR website at, on the SEC's website at and on Enerplus' website).

The purpose of our estimated free cash flow disclosure, is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. Information in this press release is provided as of the date hereof and Enerplus assumes no obligation to update any forward-looking statements, unless otherwise required by law.

In this news release, Enerplus uses the terms "adjusted funds flow", "free cash flow" (including per share measures), "net debt to adjusted funds flow ratio", and "reinvestment rate" as measures to analyze operating and financial performance. "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. "Free cash flow" is defined as "Adjusted funds flow less exploration and development capital spending".  "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. "Reinvestment rate" is calculated as exploration and development capital spending divided by adjusted funds flow.

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

SOURCE Enerplus Corporation

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