Form 6-K ENERPLUS Corp For: Apr 19
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Report of Foreign Issuer pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange Act of 1934
FOR THE MONTH OF APRIL, 2021
COMMISSION FILE NUMBER 1-15150
The Dome Tower
Suite 3000, 333 – 7th Avenue S.W.
Canada T2P 2Z1
Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
Form 20-F ◻ Form 40-F X
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)
Yes ◻ No X
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)
Yes ◻ No X
The exhibits to this report shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statements under the Securities Act of 1933 on Form F-10 (File No. 333-231548) and Form S-8 (File Nos. 333-200583 and 333-171836).
EXHIBIT 99.1 – Enerplus – Material Change Report
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Jodine J. Jenson Labrie
Jodine J. Jenson Labrie
Senior Vice President and Chief Financial Officer
DATE: April 19, 2021
MATERIAL CHANGE REPORT
Name and Address of Company
Enerplus Corporation ("Enerplus" or the "Corporation")
3000, 333 - 7th Avenue S.W.
Calgary, Alberta T2P 2Z1
April 7, 2021
Summary of Material Change
On April 8, 2021, Enerplus announced that its indirect wholly-owned subsidiary, Enerplus Resources (USA) Corporation ("Enerplus USA"), has entered into a purchase and sale agreement (the "Purchase Agreement") with Hess Bakken Investments II, LLC (the "Vendor") to acquire certain crude oil and natural gas assets of the Vendor comprised of 78,700 net acres in the Williston Basin and associated reserves, production and infrastructure (the "Acquired Assets") for total consideration of US$312 million (the "Purchase Price"), payable in cash, subject to certain customary adjustments (the "Acquisition"). Closing of the Acquisition is subject to customary closing conditions and is expected to occur in May 2021.
The Acquisition will be funded with the Corporation's existing cash position of approximately US$150 million, with the remaining portion of the Purchase Price funded through borrowing on the Corporation's undrawn US$600 million senior unsecured covenant-based credit facility with a syndicate of financial institutions maturing on October 31, 2023.
|5.1||Full Description of Material Change|
On April 7, 2021, Enerplus USA, an indirect wholly-owned subsidiary of Enerplus, entered into the Purchase Agreement to acquire the Acquired Assets for the Purchase Price, payable in cash, subject to certain customary adjustments. Closing of the Acquisition is subject to customary closing conditions and is expected to occur in May 2021.
Pursuant to the Acquisition, the Corporation will acquire 78,700 largely contiguous net acres in Dunn County, North Dakota. The Acquisition includes approximately 6,000 BOE/day (76% tight oil, 10% NGLs and 14% shale gas) of production, with a base decline rate under 20% (10% on the operated production, 37% on the non-operated production). The McDaniel Report (as defined below) has assigned 62.7 MMBOE of proved plus probable reserves to the Acquired Assets, consisting of 49.7 MMbbls of tight oil, 7.1 MMbbls of NGLs and 35.1 Bcf of shale gas. The Acquisition also includes an inventory of 153 gross
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(66.1 net) proved plus probable undeveloped reserves locations identified by McDaniel & Associates Consultants Ltd., an independent petroleum consulting firm, ("McDaniel"), 166 gross (44.5 net) unbooked potential future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators and considered economic, and 155 gross (120.7 net) unbooked potential 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 marginal economics based on the current assessment. The Acquired Assets are all located in North Dakota, with most of its interests being in the Little Knife, Murphy Creek and Russian Creek areas. See "Description of the Acquired Assets" in this material change report.
The Purchase Agreement provides for the acquisition by Enerplus USA of the Acquired Assets for the Purchase Price, payable in cash on the closing date of the Acquisition, currently anticipated to be on or about May 18, 2021 (the "Acquisition Closing Date"). The Purchase Price is subject to certain customary adjustments including, among other things, for certain title and environmental defects and for certain operating costs and expenses between the March 1, 2021 effective date of the Acquisition and the Acquisition Closing Date. Subject to certain customary exceptions, Enerplus USA will generally be entitled to receive all revenues and benefits arising from the Acquired Assets, and will be responsible for all obligations and expenditures in respect of the Acquired Assets, from and after the effective date of the Acquisition. An interim estimate of all adjustments required pursuant to the Purchase Agreement will be prepared by the Vendor on the Acquisition Closing Date, and a final settlement statement will be prepared by the Vendor within 90 days of the Acquisition Closing Date, which will be subject to final approval by Enerplus USA.
The Purchase Agreement contains a covenant in favour of Enerplus USA that allows Enerplus USA to conduct due diligence on the Acquired Assets prior to the Acquisition Closing Date, including providing Enerplus USA with reasonable access to the Acquired Assets and records relating thereto, and to conduct a Phase I environmental review thereof. In certain limited circumstances, Enerplus USA may seek Vendor's consent to conduct a Phase II environmental review, which consent may be withheld in Vendor's sole discretion; provided, however, if Vendor withholds such consent, subject to certain conditions, Enerplus USA may elect to exclude the affected assets and reduce the Purchase Price by the allocated value of the assets so excluded. Title and environmental defects that exceed certain minimum thresholds shall result in a downward adjustment to the Purchase Price by the amount that such defects exceed a deductible of 4% of the Purchase Price. If the net amount of title defects (as offset by any title benefits) and environmental defects (in each case, subject to a minimum threshold and aggregate deductible), exercised preferential rights, unobtained consents, assets excluded due to Vendor's refusal to consent to a Phase II and casualty losses resulting in a downward adjustment to the Purchase Price exceeds 15% of the Purchase Price, then either Enerplus USA or the Vendor may terminate the Purchase Agreement.
The Purchase Agreement contains customary conditions to closing of the Acquisition including, but not limited to: (a) the accuracy of each party's representations and warranties, and the performance of their respective covenants; and (b) no legal proceedings that would prohibit or seek substantial damages in connection with the Acquisition are pending before any governmental authority. In addition, the Purchase Agreement may be terminated by either party if the Acquisition Closing Date has not occurred by June 18, 2021.
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Enerplus USA has provided the Vendor with a deposit in the amount of US$31.2 million in support of its obligations pursuant to the Purchase Agreement (the "Deposit"). If the Acquisition is consummated, the Deposit will be applied towards the Purchase Price. If the Acquisition does not close due to a willful breach by Enerplus USA of the Purchase Agreement, or if Enerplus USA elects not to close the Acquisition despite all conditions to closing being satisfied or waived, the Vendor can either seek (a) to retain the Deposit or (b) specific performance. If the Acquisition does not close due to a willful breach by the Vendor of the Purchase Agreement, or if the Vendor elects not to close the Acquisition despite all conditions to closing being satisfied or waived, Enerplus USA can either seek (a) return of the Deposit, in addition to pursuing damages from the Vendor in an amount up to the amount of the Deposit, or (b) specific performance.
The Vendor has agreed to indemnify Enerplus USA for a period of twelve months from the Acquisition Closing Date in respect of certain losses and liabilities arising out of breaches of representations and warranties or a failure to perform covenants due to be performed prior to closing, subject to certain exceptions, including certain title warranties of the Vendor that will survive for two years. Enerplus USA has agreed to indemnify the Vendor after closing from and against any liabilities arising out of the ownership and operation of the Acquired Assets (whether before or after the Acquisition Closing Date), unless relating to a matter for which the Vendor has agreed to indemnify Enerplus USA. These indemnities are subject to certain limited exceptions, minimum thresholds and maximum amounts, in a manner which is customary for agreements of this type.
Description of the Acquired Assets
Description of the Acquired Assets
Outlined below is a description of crude oil and natural gas properties associated with the Acquired Assets, all of which are located in North Dakota. Primary U.S. crude oil properties associated with the Acquired Assets are located in the Little Knife, Murphy Creek and Russian Creek regions of North Dakota.
The Acquired Assets contain approximately 78,700 largely contiguous net acres of land in Little Knife, in Dunn County. On a production basis, approximately 65% of the Little Knife's properties comprising the Acquired Assets are operated. The Little Knife property produces a tight oil with some associated shale gas and NGLs, from both the Middle Bakken and Three Forks formations. Little Knife production averaged approximately 6,545 BOE/day in 2020 consisting of approximately 4,810 bbls/day of tight oil, approximately 811 bbls/day of NGLs and approximately 5,547 Mcf/day of shale gas. In the Little Knife region, 0.4 net wells were brought on-stream in 2020. In addition, 0.8 net wells were drilled in 2020 targeting the Middle Bakken and Three Forks formations and remain yet to be completed. Enerplus expects these 0.8 net drilled uncompleted wells to be completed and brought on production in 2021.
The Acquired Assets also contain working interests in the Murphy Creek and Russian Creek regions, which produced an average of approximately 622 BOE/day from the Middle Bakken formation in 2020, consisting of approximately 585 bbls/day of tight oil, approximately 26 bbls/day of NGLs and approximately 71 Mcf/day of shale gas.
Overall, the Acquired Assets produced an average of approximately 7,170 BOE/day in 2020 (75% tight oil, 12% NGLs and 13% shale gas). Total proved plus probable reserves associated with the Acquired Assets as at March 1, 2021 were approximately 62.7 MMBOE (49.7 MMbbls of tight oil, 7.1 MMbbls of NGLs and 35.1 Bcf of shale gas), as described in more detail below under " – Summary of Oil and Gas Reserves".
In 2020, the Vendor incurred capital expenditures (essentially all of which were development costs and not exploration costs) of approximately US$1.5 million in respect of the Acquired Assets. The Corporation
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anticipates that spending by the Corporation on these properties in 2021 following completion of the Acquisition will be in the range of US$15 million to US$20 million.
Summary of Principal Production Locations
The following table describes the average daily production from the principal producing properties and regions comprising the Acquired Assets during the year ended December 31, 2020.
Average Daily Production from Principal Properties and Regions
Little Knife, North Dakota
Murphy Creek, North Dakota
Russian Creek, North Dakota
Quarterly Production History
The following table sets forth average daily gross production volumes associated with the Acquired Assets by product type, for each fiscal quarter in 2020 and for the entire year. Production decreased significantly after the second quarter of 2020 due to commodity price-related oil production curtailments and minimal development capital spending on the properties.
Year Ended December 31, 2020
Tight oil (bbls/day)
Natural gas liquids (bbls/day)
Total liquids (bbls/day)
Exploration and Development Activities
In 2020, there were two gross (0.3 net) crude oil wells drilled on properties comprising the Acquired Assets.
Oil and Natural Gas Wells and Unproved Properties
As at March 1, 2021, there were 386 gross (113.6 net) producing oil wells and 49 gross (9.9 net) non-producing oil wells, which are not producing but may be capable of production, associated with the Acquired Assets. Enerplus expects that no rights to explore, develop and exploit on unproved properties associated with the Acquired Assets will expire, in the ordinary course, prior to December 31, 2021. Enerplus does not believe that a material portion of unproved properties associated with the Acquired Assets are scheduled to expire in the near term, or would require material expenditures to be made or work conducted in the near term to preserve the rights associated with those properties.
For any properties with no reserves or on unproved lands associated with the Acquired Assets, Enerplus does not believe such assets have any significant abandonment and reclamation costs, unusually high expected development costs or operating costs, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations.
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Summary of Oil and Gas Reserves
All of the reserves associated with the Acquired Assets have been independently evaluated for the Corporation in accordance with NI 51-101 by McDaniel, with an effective date of March 1, 2021 (the "McDaniel Report"). McDaniel used the average of the commodity price forecasts and inflation rates of GLJ Petroleum Consultants ("GLJ"), McDaniel and Sproule Associates Limited ("Sproule") as of January 1, 2021 to prepare its report.
The following sections and tables summarize, as of March 1, 2021, tight oil, NGLs and shale gas reserves associated with the Acquired Assets and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions pertaining to such reserves estimates. The data contained in the tables is a summary of the evaluation and, as a result, the tables may contain slightly different numbers than the evaluation due to rounding. Additionally, the columns and rows in the tables may not add due to rounding.
All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures. Such estimates are also presented before deducting income taxes as the McDaniel Report evaluated the Acquired Assets on a stand-alone basis, without considering corporate tax rates or tax pools of the Vendor or the Corporation. With respect to pricing information in the following reserves information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and transportation. The NGLs prices were adjusted to reflect historical average prices received.
It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The reserves estimates of tight oil, NGLs and shale gas reserves associated with the Acquired Assets provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein.
The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to reserves associated with the Acquired Assets as of March 1, 2021, using forecast price and cost cases.
Summary of Oil and Gas Reserves (Forecast Prices and Costs)
As of March 1, 2021
OIL AND NATURAL GAS RESERVES
Proved Developed Producing
Total Proved Plus Probable
Gross reserves are working interest reserves before royalty deductions.
Net reserves are working interest reserves after royalty deductions plus royalty interest reserves.
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Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves (Forecast Prices and Costs)
As of March 1, 2021
NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)
Before Deducting Income Taxes
(in $ millions)
Proved Developed Producing
Total Proved Plus Probable
Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes.
Forecast Prices and Costs
The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021, and the following inflation and exchange rate assumptions:
West Texas Intermediate at Cushing Oklahoma 40o API/0.5% sulphur.
Escalation is approximately 2% per year thereafter.
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Undiscounted Future Net Revenue by Resources Category
Future Net Revenue
(in $ millions)
Proved Plus Probable
Includes all product revenues and other revenues as forecast.
Royalties include any net profits interests paid.
Net Present Value of Future Net Revenue by Reserves Category and Product Type
The net present value of future net revenue before income taxes by reserves category and product type as of March 1, 2021, using forecast prices and costs and discounted at 10% per year, is set forth below:
(Discounted at 10%)
(in $ thousands)
Proved Plus Probable Reserves
Unit values are calculated using the 10% discounted rate divided by the major product type net reserves for each group, which is only comprised of tight oil.
Including net present value of solution gas and other by-products.
Including net present value of by-products, but excluding solution gas and by-products from oil wells.
Estimated Production for Gross Reserves Estimates
The volume of total production associated with the Acquired Assets estimated for March 1, 2021 through December 31, 2021 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual production may vary from the estimates below as the actual development programs, timing and priorities on the Acquired Assets conducted by the Corporation following closing of the Acquisition may differ from the forecast of development. Columns may not add due to rounding.
Gross Proved Reserves
Gross Probable Reserves
Gross Proved and Probable Reserves
Total Crude Oil
Natural Gas Liquids
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Future Development Costs
The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. The Corporation intends to fund its development activities through cash, internally generated cash flow and/or debt. The Corporation does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on the Corporation's disclosed oil and gas reserves or future net revenue attributable to those reserves.
Significant Factors or Uncertainties
Changes in future commodity prices relative to the forecasts described above under "Forecast Prices and Costs" could have a negative impact on reserves and, in particular, on the development of undeveloped reserves associated with the Acquired Assets, unless future development costs are adjusted in parallel. Other than the foregoing and the factors disclosed or described in the tables above, the Corporation does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of reserves data associated with the Acquired Assets.
In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines, including on properties associated with the Acquired Assets. The Corporation budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. There are no unusually significant abandonment and reclamation costs associated with reserves properties or properties with no attributed reserves associated with the Acquired Assets, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact reserves data associated with the Acquired Assets or its ability to develop these reserves at this time.
Marketing Arrangement and Forward Contracts
Crude oil production associated with the Acquired Assets is marketed to various buyers using a mix of negotiated contracts. Crude oil production associated with the Acquired Assets is transported to buyers by pipeline and/or truck. At times, a portion of such North Dakota crude oil production may be transported to the U.S. Gulf Coast, where it can further access export crude oil markets. NGLs associated with crude oil production volumes are marketed by midstream companies in North Dakota.
All of the natural gas production associated with the Acquired Assets was shale gas production from tight oil operations in North Dakota. These volumes are not marketed directly, as they are marketed by midstream companies in North Dakota.
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|5.2||Disclosure for Restructuring Transactions|
|6.||Reliance on Subsection 7.1(2) of National Instrument 51-102|
The name and business telephone number of an executive officer of the Corporation who is knowledgeable about the material change and this material change report is:
Jodi Jenson Labrie, Senior Vice-President & Chief Financial Officer
Tel: (403) 298-2200
Date of Report
April 16, 2021.
All amounts in this material change report are stated in Canadian dollars unless otherwise specified.
Forward-Looking Information and Statements
This material change report 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 material change report contains forward-looking information pertaining to the following: anticipated completion of the Acquisition, including expected purchase price, terms, and timing of completion thereof; and expected benefits of the Acquisition.
The forward-looking information contained in this material change report 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 material change report; and that Enerplus will realize the expected benefits of the Acquisition described in this material change report. 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 material change report 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 material change report; failure by Enerplus to realize anticipated benefits of the Acquisition; and other risks set forth in this material change report and other risks detailed from time to time in the Corporation's public disclosure documents.
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Presentation of Information in this Material Change Report
Information about the Acquired Assets
As the Corporation does not currently own the Acquired Assets, the information in this material change report relating to the Acquired Assets, has been summarized from information obtained from the Vendor and its affiliates. None of the Vendor or any of its affiliates or their respective directors, officers, employees, shareholders, members, partners, agents or other representatives (each, a "Vendor Party") makes any representation or warranty as to the accuracy or completeness of the information regarding the Acquired Assets or the Vendor contained in this material change report, and no Vendor Party was involved in the preparation or assembly of this material change report. No Vendor Party assumes any responsibility or liability for any errors or omissions in, or for any damages resulting from the use of, or any reliance on, any part of the information contained in this material change report.
The McDaniel Report on the Acquired Assets effective March 1, 2021 was prepared on behalf of the Corporation with information provided by the Corporation and other industry information available to McDaniel, and no Vendor Party participated in or provided any information to McDaniel in respect of such report.
Unless otherwise stated, all of the reserves information contained in this material change report has been prepared and presented in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulatory authorities, and the reserves definitions contained in the Canadian Securities Administrators Staff Notice 51-324. Unless otherwise stated, all of the reserves information in this material change report is on "gross" basis, which are working interest share before deduction of royalties and without including any royalty interests. Unless otherwise stated, all of the production information in this material change report is on a "company interest" basis, which are working interest share before deduction of royalties and including any royalty interests. Additionally, the oil and gas production volumes associated with the Acquired Assets that were made available to Enerplus were determined on a net basis, consistent with U.S. disclosure requirements and industry practice, and the Corporation has estimated company interest production volumes based on royalty and other information available to it.
The Corporation's actual oil and natural gas reserves and future production, including following completion of the Acquisition, may be greater than or less than the estimates provided in this material change report. The estimated future net revenue from the production of such oil and natural gas reserves does not necessarily represent the fair market value of such reserves.
Barrels of Oil Equivalent
The Corporation has adopted the standard of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to barrels of oil equivalent. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of six to one, utilizing a conversion on a six to one basis may be misleading as an indication of value.
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In this material change report, the following abbreviations have the meanings set forth below:
barrels (with each barrel representing 34.972 imperial gallons or 42 U.S. gallons) per day
billion cubic feet
barrels of oil equivalent
barrels of oil equivalent per day
one thousand barrels
one thousand barrels of oil equivalent
one thousand cubic feet
one thousand cubic feet per day
one million barrels
one million barrels of oil equivalent
one million cubic feet
natural gas liquids
West Texas Intermediate
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