ERF Enerplus Corporation

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FORM 6-K

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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Report of Foreign Private Issuer pursuant to Rule 13-a-16 or 15d-16

of the Securities Exchange Act of 1934

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FOR THE MONTH OF MAY, 2023

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COMMISSION FILE NUMBER 1-15150

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The Dome Tower

Suite 3000, 333 – 7^th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

(403) 298-2200

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US Bank Tower

Suite 2200, 950 – 17^th Street

Denver, Colorado

United States of America 80202-2805

(720) 279-5500

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Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

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Form 20-F ◻ Form 40-F X

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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

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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

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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. 333-257151) and Form S-8 (File No. 333-200583).

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EXHIBIT INDEX

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EXHIBIT 99.1 — Management’s Discussion and Analysis for the First Quarter ended March 31, 2023

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EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 2023

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EXHIBIT 99.3 — Certification of the Chief Executive Officer

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EXHIBIT 99.4 — Certification of the Chief Financial Officer

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SIGNATURE

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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.

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DATE: May 4, 2023

        MD&A

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Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)

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The following discussion and analysis of financial results is dated May 4, 2023 and is to be read in conjunction with:

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The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non-GAAP Measures” at the end of the MD&A for further information. In addition, the following MD&A contains disclosure regarding certain risks and uncertainties associated with Enerplus’ business. See “Risk Factors and Risk Management” in the Annual MD&A and “Risk Factors” in Enerplus’ Annual Information Form for the year ended December 31, 2022 (the “Annual Information Form”).

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BASIS OF PRESENTATION

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The Interim Financial Statements and notes thereto have been prepared in accordance with U.S. GAAP. Unless otherwise stated, all dollar amounts are presented in U.S. dollars. Certain prior period amounts have been restated to conform with current period presentation as a result of the voluntary and retroactively applied change in the presentation currency from Canadian to U.S. dollars adopted by the Company in the fourth quarter of 2021.

The functional currency of the parent company changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change as of January 1, 2023 in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiaries. All assets and liabilities held by the parent company were translated at the exchange rate at December 31, 2022 to determine opening balances in U.S. dollars.  Amounts that are part of Shareholders’ Equity of the parent company were translated at historical exchange rates. Monetary assets and liabilities denominated in Canadian dollars will be revalued at current exchange rates at each reporting period. Upon settlement and/or realization of Canadian dollar denominated assets and liabilities, there may be realized foreign exchange gains and losses depending on the change in the foreign exchange rate when the transaction was originally recorded and the final settlement date.  

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and crude oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. The BOE and Mcfe rates are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1 or 0.167:1, as applicable, utilizing a conversion on this basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading.

In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in the Financial Statements. In addition, unless otherwise noted, all production volumes are presented on a “net” basis (after deduction of royalty obligations plus the Company’s royalty interests) consistent with U.S. oil and gas reporting standards.

All references to “liquids” in this MD&A include light and medium oil, heavy oil and tight oil (all together referred to as “crude oil”) and natural gas liquids on a combined basis. All references to “natural gas” in this MD&A include conventional natural gas and shale gas.

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OVERVIEW

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Production during the first quarter of 2023 averaged 97,652 BOE/day, a decrease of 9% compared to average production of 106,915 BOE/day in the fourth quarter of 2022, with crude oil and natural gas liquids production decreasing by 13% over the same period. The decrease in production was due to the sale of substantially all of our Canadian assets in the fourth quarter of 2022 with associated production of 6,400 BOE/day (78% liquids), and the planned sequencing of the Company’s completions program in North Dakota with no operated wells brought online between mid-October 2022 and mid-February 2023. We are maintaining our average annual production guidance for 2023 of 93,000 BOE/day - 98,000 BOE/day, including 57,000 bbls/day - 61,000 bbls/day of crude oil and natural gas liquids production.

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During the first quarter of 2023, a total of $66.6 million was returned to shareholders through share repurchases and dividends. As previously announced, we plan to return at least 60% of free cash flow¹ to our shareholders in 2023 through share repurchases and dividends, based on current market conditions. In connection with this plan, the Board of Directors approved a second quarter dividend of $0.055 per share to be paid in June 2023. Based on current market conditions, the Company expects to continue to prioritize share repurchases for the majority of its return of capital plan and intends to complete its remaining Normal Course Issuer Bid (“NCIB”) authorization by the end of July 2023. We expect to fund the dividend and share repurchases through the free cash flow generated by the business.

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Capital spending during the first quarter of 2023 was $138.6 million, compared to $85.6 million during the fourth quarter of 2022, with the majority of the spending focused on our U.S. crude oil properties. The increase in capital spending was due to increased drilling and completions activity on our North Dakota properties, offset by reduced capital activity on our Marcellus natural gas assets. We continue to expect capital spending for 2023 to range between $500 - $550 million.

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Our realized Bakken crude oil price differential averaged $0.06/bbl above WTI during the first quarter of 2023, compared to $1.05/bbl above WTI during the fourth quarter of 2022. The weaker realized differential was due to lower prices for crude oil delivered to the U.S. Gulf Coast and a decrease in U.S. refinery demand due to seasonal maintenance. Given the slightly weaker than expected pricing in the first quarter of 2023, we expect our 2023 realized Bakken crude oil price differential to average $0.50/bbl above WTI, compared to previous guidance of $0.75/bbl above WTI.

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Our realized Marcellus sales price differential averaged $0.64/Mcf below NYMEX in the first quarter of 2023 compared to $1.18/Mcf below NYMEX in the fourth quarter of 2022. The narrower differential was due to strong regional prices in January 2023, particularly in the Transco Zone 6 Non-New York market. A significant portion of our production receives prices reflecting market conditions south of New York at Transco Zone 6 Non-New York, which averaged $3.35/Mcf above NYMEX in the first quarter of 2023 compared to a discount to NYMEX in the fourth quarter of 2022. We continue to expect our annual realized Marcellus differential to average $0.75/Mcf below NYMEX.

Operating expenses for the first quarter of 2023 decreased to $92.8 million, or $10.56/BOE, compared to $95.2 million, or $9.68/BOE during the fourth quarter of 2022. On a per BOE basis, the increase was due to lower production during the first quarter of 2023, inflation adjusted contract pricing and higher planned well service activity. We continue to expect our operating expenses for 2023 to range between $10.75/BOE – $11.75/BOE.

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We reported net income of $137.5 million in the first quarter of 2023, compared to net income of $330.7 million in the fourth quarter of 2022. Net income decreased primarily due to a $151.9 million gain on the sale of substantially all of our Canadian assets recorded in the fourth quarter of 2022, and lower production and commodity prices in the first quarter of 2023.

In the first quarter of 2023, cash flow from operating activities and adjusted funds flow decreased to $241.4 million and $260.4 million, respectively, compared to $316.6 million and $315.4 million in the fourth quarter of 2022. The decrease was primarily due to lower production and commodity prices, offset by higher realized commodity derivative instrument gains.

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At March 31, 2023 net debt decreased to $150.6 million, compared to $221.5 million at December 31, 2022. Net debt was calculated as total debt, which was comprised of our senior notes, less cash on hand of $52.6 million. We were undrawn on our $900 million sustainability linked lending (“SLL”) bank credit facility and our $365 million SLL bank credit facility (together referred to as the “Bank Credit Facilities”), at March 31, 2023. Our net debt to adjusted funds flow ratio decreased to 0.1x from 0.2x in the fourth quarter of 2022.

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¹ This financial measure is a non-GAAP measure. See “Non-GAAP Measures” section in this MD&A.

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RESULTS OF OPERATIONS

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Production

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Production during the first quarter of 2023 averaged 97,652 BOE/day, a decrease of 9% compared to average production of 106,915 BOE/day in the fourth quarter of 2022, with crude oil and natural gas liquids production decreasing by 13% over the same period. The decrease in production was due to the sale of substantially all of our Canadian assets in the fourth quarter of 2022 with associated production of 6,400 BOE/day (78% liquids), and the planned sequencing of the Company’s completions program in North Dakota with no operated wells brought online between mid-October 2022 and mid-February 2023.

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For the three months ended March 31, 2023, total production increased by 6% when compared to the same period in 2022. The increase in production was due to strong well performance on new wells brought online and increased drilling and completions activity in both North Dakota and the Marcellus during 2022, offset by the sale of substantially all of our Canadian assets in the fourth quarter of 2022.

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Our crude oil and natural gas liquids weighting in the first quarter of 2023 decreased to 58% from 61%, compared to the same period in 2022, primarily due to the Canadian asset divestments in the fourth quarter of 2022.

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We are maintaining our annual average production guidance for 2023 of 93,000 BOE/day - 98,000 BOE/day, including 57,000 bbls/day - 61,000 bbls/day of crude oil and natural gas liquids production.

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Average daily production volumes for the three months ended March 31, 2023 and 2022 are outlined below:

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Pricing

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The prices received for crude oil, natural gas liquids and natural gas production directly impact our earnings, cash flow from operating activities, adjusted funds flow and financial condition. The following table compares quarterly average benchmark prices, selling prices and differentials:

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CRUDE OIL AND NATURAL GAS LIQUIDS

During the first quarter of 2023, our realized crude oil sales price averaged $76.34/bbl, a decrease of 8% compared to the fourth quarter of 2022, and in line with the decrease in the underlying benchmark WTI price over the same period. WTI crude oil declined during the first quarter of 2023 primarily due to demand-related concerns resulting from rising interest rates as well as concerns over a global recession. Additionally, crude oil inventories built up during the quarter due to seasonal declines in demand with scheduled refinery maintenance. In response to the decline in global oil prices in late March 2023, the Organization of the Petroleum Exporting Countries (“OPEC”) voluntarily reduced production targets for the remainder of the year beginning May 2023, in an effort to stabilize crude oil prices.

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Our realized Bakken crude oil price differential averaged $0.06/bbl above WTI during the first quarter of 2023, compared to $1.05/bbl above WTI during the fourth quarter of 2022. The weaker realized differential was due to lower prices for crude oil delivered to the U.S. Gulf Coast and a decrease in U.S. refinery demand due to seasonal maintenance. Given slightly weaker than expected pricing, we expect our 2023 realized Bakken crude oil price differential to average $0.50/bbl above WTI, compared to previous guidance of $0.75/bbl above WTI.

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Our realized sales price for natural gas liquids averaged $20.55/bbl during the first quarter of 2023 compared to $21.88/bbl during the fourth quarter of 2022, which was largely in line with changes to benchmark liquids prices during the quarter.

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NATURAL GAS

Our realized natural gas sales price averaged $3.08/Mcf during the first quarter of 2023, a decrease of 35% compared to the fourth quarter of 2022, while the NYMEX benchmark price decreased by 45% over the same period. The difference in price realization versus the benchmark was due to seasonally stronger gas prices in the Marcellus, resulting in a narrower differential in the first quarter of 2023.

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In the Marcellus, our sales price differential averaged $0.64/Mcf below NYMEX in the first quarter of 2023 compared to $1.18/Mcf below NYMEX in the fourth quarter of 2022. The narrower differential was due to stronger regional prices in January 2023, particularly in the Transco Zone 6 Non-New York market. We expect our Marcellus differential to remain supported during spring and into summer due to a flat outlook on natural gas supply growth, despite weaker NYMEX pricing. As a result, we are maintaining our annual guidance of $0.75/Mcf below NYMEX.

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FOREIGN EXCHANGE

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Fluctuations in the CDN/US dollar exchange rate impacts our Canadian dollar denominated amounts such as general and administrative (“G&A”) expenses and dividends paid to shareholders who have elected to receive dividends in Canadian dollars. The period end exchange rate was consistent at March 31, 2023, compared to December 31, 2022, at $0.74 CDN/US. The average Canadian dollar exchange rate of $0.74 CDN/US for the first quarter of 2023 was weaker than the same period in 2022 when it averaged $0.79 CDN/US.

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Price Risk Management

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We have a price risk management program that considers our overall financial position and the economics of our capital program.  

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We expect our commodity derivative contracts to continue to protect a portion of our cash flow from operating activities and adjusted funds flow. As of May 3, 2023, we have hedged 15,000 bbls/day of WTI exposure for the second quarter of 2023, and 5,000 bbls/day for the second half of 2023. We have also hedged 50,000 Mcf/day of NYMEX exposure for the period from April 1, 2023 to October 31, 2023. Our crude oil contracts include three-way collars, which limits upward price participation to the call strike level; additionally, the sold put limits the amount of downside protection we have to the difference between the strike price of the purchased and sold puts.

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The following is a summary of our financial contracts in place at May 3, 2023:

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ACCOUNTING FOR PRICE RISK MANAGEMENT

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During the three months ended March 31, 2023, Enerplus realized gains of $3.4 million on our crude oil contracts, compared to realized losses of $72.7 million for the same period in 2022. For the three months ended March 31, 2023, realized gains of $30.9 million were recorded on our natural gas contracts, compared to realized losses of $0.4 million for the same period in 2022. Realized gains recorded during the three months ended March 31, 2023 were due to commodity prices falling below the purchased put values on our commodity derivative contracts.

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As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At March 31, 2023, the fair value of our crude oil and natural gas contracts was in a net asset position of $20.5 million (December 31, 2022 – net asset position of $26.1 million). For the three months ended March 31, 2023, the change in the fair value of our crude oil contracts resulted in an unrealized gain of $3.8 million, compared to an unrealized loss of $95.7 million during the same period in 2022. For the three months ended March 31, 2023, we recorded an unrealized loss on our natural gas contracts of $10.1 million, compared to an unrealized loss of $38.0 million during the same period in 2022.

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Crude Oil and Natural Gas Sales

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Crude oil and natural gas sales for the three months ended March 31, 2023 were $413.2 million or $47.02/BOE, compared to $513.2 million or $61.84/BOE for the same period in 2022. The decrease in revenue was primarily due to lower commodity prices.

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Operating Expenses

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For three months ended March 31, 2023, operating expenses were $92.8 million, or $10.56/BOE, compared to $83.2 million, or $10.03/BOE, for the same period in 2022. The increase was due to inflation adjusted contract pricing, increased gas processing volumes due to improved capture rates, and higher planned well service activity.

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We continue to expect our operating expenses for 2023 to range between $10.75/BOE – $11.75/BOE.

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Transportation Costs

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For three months ended March 31, 2023, transportation costs were $37.8 million, or $4.30/BOE, consistent with $35.8 million, or $4.32/BOE, for the same period in 2022.

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We are revising our transportation costs guidance for 2023 to $4.20/BOE from $4.35/BOE.

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Production Taxes

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Production taxes for three months ended March 31, 2023 were $30.1 million, or 7.3%, compared to $35.4 million, or 6.9%, for the same period in 2022. The decrease in total production taxes was due to lower realized prices and the effect of the Canadian divestments in the fourth quarter of 2022, partially offset by increased U.S. crude oil production which has higher rates of production tax.

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We are revising our production taxes guidance for 2023 to range between 7% - 8% from an average of 7%.

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Netbacks

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The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and, as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.

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Total netbacks before hedging were lower for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to lower realized prices. Total netbacks after hedging for the three months ended March 31, 2023 were consistent with the same period in 2022.

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For the three months ended March 31, 2023, crude oil properties accounted for 89% of total netback before hedging, compared to 84% during the same period in 2022. 

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G&A Expenses

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Total G&A expenses include G&A expenses and share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”).

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Cash G&A expenses for three months ended March 31, 2023 were $13.0 million, or $1.48/BOE, compared to $11.2 million, or $1.35/BOE for the same period in 2022. Total cash G&A expenses increased due to inflationary pressure on labour and services.

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SBC can be equity-settled or cash-settled, depending on the underlying plan to which it relates. Cash-settled SBC recovery was $0.9 million or $0.10/BOE for the three months ended March 31, 2023, compared to an expense of $2.1 million or $0.25/BOE for the same period in 2022, and relates to our director plans. The recovery was due to a decrease in Enerplus’ share price in 2023 compared to an increase in share price in the same period in 2022.

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Equity-settled non-cash SBC was $7.5 million or $0.85/BOE for the three months ended March 31, 2023, compared to $4.8 million or $0.58/BOE, for the same period in 2022. Performance Share Units (“PSUs”), as one of the equity-settled LTI plans, are impacted by performance multipliers. For the three months ended March 31, 2023, the applicable multiplier was higher, resulting in an increase in expense compared to the same period in 2022.  

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Enerplus previously had hedged a portion of the outstanding cash-settled units under our LTI plans. In the first quarter of 2022, we recorded a market-to-market gain of $0.4 million, as a result of the higher share price. Enerplus settled its equity derivative contracts during 2022 and did not have any equity derivatives outstanding at March 31, 2023.

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We continue to expect our cash G&A expenses guidance for 2023 to be $1.35/BOE.

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Interest Expense

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For the three months ended March 31, 2023, we recorded a total interest expense of $4.3 million compared to $6.1 million for the same period in 2022. The decrease was primarily due to lower debt levels in the first quarter of 2023, compared to the first quarter of 2022, as free cash flow was used to repay debt.

At March 31, 2023, our Bank Credit Facilities were undrawn and all of Enerplus’ debt was based on fixed interest rates (December 31, 2022 – 78% fixed and 22% floating), with a weighted average interest rate of 4.1% (December 31, 2022 – 4.1% fixed and 5.7% floating).

Foreign Exchange

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For three months ended March 31, 2023, Enerplus recorded a foreign exchange gain of $0.1 million compared to a loss of $0.9 million for the same period in 2022.

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Enerplus is exposed to foreign exchange risk as it relates to certain activities transacted in Canadian dollars. The parent company and its subsidiaries have a U.S. dollar functional currency, and the parent company has both U.S. and Canadian dollar transactions. Canadian denominated monetary assets and liabilities are subject to revaluation from the source currency of Canadian dollars to the functional currency of U.S. dollars, generating realized and unrealized foreign exchange (gains)/losses in the Condensed Consolidated Statements of Income/(Loss).

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Following the change in functional currency of the parent company to U.S. dollars on January 1, 2023, the net investment hedge on the U.S. dollar denominated debt held in the parent entity for the U.S. subsidiaries was no longer required. Previously, the unrealized foreign exchange gains and losses arising from the translation of the debt were recorded in Other Comprehensive Income/(Loss), net of tax, and were limited by the cumulative translation gain or loss on the net investment in the U.S. subsidiaries. For the three months ended March 31, 2023, there was no unrealized foreign exchange gain or loss recorded in Other Comprehensive Income/(Loss) compared to an unrealized gain of $5.4 million on Enerplus’ U.S. denominated senior notes and Bank Credit Facilities for the three months ended March 31, 2022. 

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Property, Plant and Equipment (“PP&E”)

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Capital spending for the three months ended March 31, 2023 totaled $138.6 million, compared to $99.0 million for the same period in 2022. The increase was mainly due to increased capital activity on our North Dakota properties. Capital spending during the first quarter of 2023 included $134.6 million on our U.S. crude oil properties and $4.0 million on our Marcellus natural gas properties. 

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We continue to expect capital spending for 2023 to range between $500 - $550 million.

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Depletion, Depreciation and Accretion (“DD&A”)

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DD&A related to PP&E is recognized using the unit of production method based on proved reserves. Enerplus recorded DD&A expense of $87.1 million, or $9.91/BOE, for the three months ended March 31, 2023 compared to $66.7 million, or $8.04/BOE, in the same period in 2022. The increase in per BOE for the three months ended March 31, 2023 is primarily a result of reserve additions and revisions at December 31, 2022.

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Asset Retirement Obligation (“ARO”)

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In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total ARO included on the Condensed Consolidated Balance Sheet is based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate, the timing of the costs to be incurred in future periods and estimates for inflation. We have estimated the net present value of our asset retirement obligation to be $116.1 million at March 31, 2023, compared to $114.7 million at December 31, 2022.

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For the three months ended March 31, 2023, ARO settlements were $6.8 million, compared to $8.8 million during the same period in 2022.

During 2022, Enerplus benefited from provincial government assistance to support the clean-up of inactive or abandoned crude oil and natural gas wells. These programs provided direct funding to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. During the first quarter of 2022, Enerplus benefited from $0.4 million in government assistance.

Income Taxes

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For the three months ended March 31, 2023, we recorded a current tax expense of $11.0 million compared to $5.0 million for the same period in 2022. Current tax expense in 2023 was higher compared to 2022 as a result of utilizing all of our net operating losses in 2022. Many factors influence taxable income including future commodity prices, production levels, development activities, capital spending, and overall profitability. We continue to expect current tax expense of 5.0% – 6.0% of adjusted funds flow before tax based on guidance pricing.

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For the three months ended March 31, 2023, we recorded a deferred income tax expense of $23.9 million, compared to an expense of $9.8 million for the same period in 2022 due to higher income during the first quarter of 2023.

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We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not all or a portion of our deferred income tax assets will not be realized. We have considered available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. This assessment is primarily the result of projecting future taxable income using total proved and probable forecast average prices and costs. There is risk of a valuation allowance in future periods if commodity prices weaken or other evidence indicates that some of our deferred income tax assets will not be realized. See “Risk Factors and Risk Management – Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets” in the Annual MD&A. For the three months ended March 31, 2023, no valuation allowance was recorded against our Canadian income related deferred tax asset, however, a full valuation allowance has been recorded against our deferred income tax assets related to capital items.  Our deferred income tax asset recorded in Canada was $150.3 million offset by a deferred income tax liability in the U.S of $74.5 million at March 31, 2023 (December 31, 2022 - $155.0 million deferred income tax asset in Canada offset by a $55.4 million deferred income tax liability in the U.S.).

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LIQUIDITY AND CAPITAL RESOURCES

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There are numerous factors that influence how we assess liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, commodity derivative contracts, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At March 31, 2023, our senior debt to adjusted EBITDA ratio was 0.2x and our net debt to adjusted funds flow ratio was 0.1x. Although a capital management measure that is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate liquidity.

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Net debt at March 31, 2023 decreased to $150.6 million, compared to $221.5 million at December 31, 2022. Net debt was comprised of our senior notes totaling $203.2 million, less cash on hand of $52.6 million.

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At March 31, 2023, through our Bank Credit Facilities, we had total credit capacity of $1.3 billion. We expect to finance our working capital requirements through cash, adjusted funds flow and our credit capacity. We have sufficient liquidity to meet our financial commitments for the near term.

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Our reinvestment rate¹ was 53% for the three months ended March 31, 2023, compared to 38% for the same period in 2022.

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During the first quarter of 2023, a total of $66.6 million was returned to shareholders through share repurchases and dividends, compared to $45.1 million for the same period in 2022. During the three months ended March 31, 2023, a total of 3.5 million common shares were repurchased and cancelled under the NCIB at an average price of $15.37 per share, for total consideration of $54.6 million. During the three months ended March 31, 2022, 3.1 million common shares were repurchased and cancelled under the NCIB at an average price of $11.87 per share, for total consideration of $37.2 million. Subsequent to March 31, 2023 and up to and including May 3, 2023, we repurchased 1.1 million common shares under the NCIB at an average price of $14.81 per share, for total consideration of $16.0 million.

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We plan to continue to return at least 60% of free cash flow² to our shareholders in 2023 through share repurchases and dividends, based on current market conditions. Remaining free cash flow not allocated to return of capital is expected to be directed to reinforcing the balance sheet. We intend to complete the current NCIB authorization by the end of July 2023 and subsequently renew the NCIB in August 2023. Subsequent to March 31, 2023, the Board of Directors approved a second quarter dividend of $0.055 per share to be paid in June 2023. We expect to fund the dividend through the free cash flow generated by the business.

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At March 31, 2023, we were in compliance with all covenants under the Bank Credit Facilities and outstanding senior notes. If we exceed or anticipate exceeding our covenants, we may be required to repay, refinance or renegotiate the terms of the debt. See “Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief” in the Annual Information Form. Agreements relating to our Bank Credit Facilities and the senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com. 

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¹ This financial measure is a supplementary financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

² This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

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The following table lists our financial covenants at March 31, 2023:

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Definitions

“Senior debt” is calculated as the sum of drawn amounts on our bank credit facilities, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, accretion, impairment and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended March 31, 2023 was $275.7 million and $1,364.5 million, respectively.

“Total debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $823.7 million adjustment related to our adoption of U.S. GAAP.

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Footnotes

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Dividends

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During the three months ended March 31, 2023, we declared total dividends of $12.0 million, or $0.055 per share, compared to $7.9 million, or $0.033 per share, for the same period in 2022. The total amount of dividends paid to shareholders has increased compared to the same period in 2023 due to the increased sustainability of the business and as a result of our return of capital plan.

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Subsequent to March 31, 2023, the Board of Directors approved a second quarter dividend of $0.055 per share to be paid in June 2023. We expect to fund the dividend through the free cash flow generated by the business.

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Shareholders’ Capital

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For the three months ended March 31, 2023, a total of 2.3 million units vested pursuant to our treasury-settled LTI plans, including the impact of performance multipliers (2022 – 2.2 million). In total, 1.3 million shares were issued from treasury and $7.2 million was transferred from paid-in capital to share capital (2022 – 1.2 million shares; $8.0 million). We elected to cash-settle the remaining units related to the required tax withholdings for the total amount of $16.4 million (2022 – $11.6 million). 

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On August 16, 2022, Enerplus renewed its NCIB to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange rules) during the following 12-month period.

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During the three months ended March 31, 2023, 3.5 million common shares were repurchased and cancelled under the NCIB at an average price of $15.37 per share, for total consideration of $54.6 million. Of the amount paid, $32.9 million was charged to share capital and $21.7 million was added to accumulated deficit. At March 31, 2023, 4,334,652 common shares remain available for repurchase under the current NCIB.

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During the three months ended March 31, 2022, 3.1 million common shares were repurchased and cancelled under the NCIB at an average price of $11.87 per share, for total consideration of $37.2 million. Of the amount paid, $31.3 million was charged to share capital and $5.9 million was added to accumulated deficit.

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Subsequent to March 31, 2023 and up to May 3, 2023, we repurchased 1.1 million common shares under the NCIB at an average price of $14.81 per common share, for total consideration of $16.0 million.

At May 3, 2023, we had 213,957,617 common shares outstanding. In addition, an aggregate of 7,933,093 common shares may be issued to settle outstanding grants under the PSUs and Restricted Share Unit plans assuming the maximum performance multiplier of 2.0 times for the PSUs.

QUARTERLY FINANCIAL INFORMATION

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Crude oil and natural gas sales decreased to $413.2 million during the first quarter of 2023, compared to $548.7 million during the fourth quarter of 2022. The decrease in crude oil and natural gas sales was a result of lower production, including the impact of the Canadian asset divestments during the fourth quarter of 2022, and lower commodity prices during the first quarter of 2023 compared to the fourth quarter of 2022. We reported net income of $137.5 million during the first quarter of 2023 compared to net income of $330.7 million during the fourth quarter of 2022. The decrease in net income was primarily due to the gain on the Canadian asset divestments in the fourth quarter of 2022, partially offset by a commodity derivative instrument gain of $28.0 million during the first quarter of 2023, compared to a $0.3 million loss in the fourth quarter of 2022.

Crude oil and natural gas sales increased in 2022, compared to 2021, due to higher production and improved realized pricing. Net income increased in 2022, compared to 2021, due to higher production and commodity prices as well as the gain on the Canadian asset divestments recorded in the fourth quarter of 2022.

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RECENT ACCOUNTING STANDARDS

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We have not early adopted any accounting standard, interpretation or amendment that has been issued but is not yet effective. Our significant accounting policies remain unchanged from December 31, 2022.

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2023 GUIDANCE⁽¹⁾

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NON-GAAP MEASURES

This MD&A includes references to certain non-GAAP financial measures and non-GAAP ratios used by the Company to evaluate its financial performance, financial position or cash flow. Non-GAAP financial measures are financial measures disclosed by a company that (a) depict historical or expected future financial performance, financial position or cash flow of a company, (b) with respect to their composition, exclude amounts that are included in, or include amounts that are excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the company, (c) are not disclosed in the financial statements of the company and (d) are not a ratio, fraction, percentage or similar representation. Non-GAAP ratios are financial measures disclosed by a company that are in the form of a ratio, fraction, percentage or similar representation that has a non-GAAP financial measure as one or more of its components, and that are not disclosed in the financial statements of the company.

These non-GAAP financial measures and non-GAAP ratios do not have standardized meanings or definitions as prescribed by U.S. GAAP and may not be comparable with the calculation of similar financial measures by other entities.

For each measure, we have: (a) indicated the composition of the measure; (b) identified the most directly comparable GAAP financial measure and provided comparative detail where appropriate; (c) indicated the reconciliation of the measure to the most directly comparable GAAP financial measure to the extent one exists; and (d) provided details on the usefulness of the measure for the reader. These non-GAAP financial measures and non-GAAP ratios should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP.

“Adjusted net income/(loss)” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the company by adjusting for certain unrealized items and other items that the company considers appropriate to adjust given their irregular nature. The most directly comparable GAAP measure is net income/(loss).

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“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending. The most directly comparable GAAP measure is cash flow from operating activities.

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“Netback before impact of commodity derivative contracts” and “Netback after impact of commodity derivative contracts” is used by Enerplus and is useful to investors and securities analysts, in evaluating operating performance of our crude oil and natural gas assets, both before and after consideration of our realized gain/(loss) on commodity derivative instruments. A direct GAAP equivalent does not exist for these measures, although a reconciliation is provided below:

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Other Financial Measures

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CAPITAL MANAGEMENT MEASURES

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Capital management measures are financial measures disclosed by a company that (a) are intended to enable an individual to evaluate a company’s objectives, policies and processes for managing the company’s capital, (b) are not a component of a line item disclosed in the primary financial statements of the company, (c) are disclosed in the notes to the financial statements of the company, and (d) are not disclosed in the primary financial statements of the company. The following section provides an explanation of the composition of those capital management measures if not previously provided:

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“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts, in analyzing operating and financial performance, leverage and liquidity. The most directly comparable GAAP measure is cash flow from operating activities. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

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“Net debt” is calculated as current and long-term debt associated with senior notes plus any outstanding Bank Credit Facilities balances, less cash and cash equivalents. “Net debt” is useful to investors and securities analysts in analyzing financial liquidity and Enerplus considers net debt to be a key measure of capital management.

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“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as net debt divided by a trailing twelve months of adjusted funds flow. There is no directly comparable GAAP equivalent for this measure, and it is not equivalent to any of our debt covenants.

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SUPPLEMENTARY FINANCIAL MEASURES

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Supplementary financial measures are financial measures disclosed by a company that (a) are, or are intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of a company, (b) are not disclosed in the financial statements of the company, (c) are not non-GAAP financial measures, and (d) are not non-GAAP ratios. The following section provides an explanation of the composition of those supplementary financial measures if not previously provided:

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“Capital spending” Capital and office expenditures, excluding other capital assets/office capital and property and land acquisitions and divestments.

“Cash general and administrative expenses” or “Cash G&A expenses” General and administrative expenses that are settled through cash payout, as opposed to expenses that relate to accretion or other non-cash allocations that are recorded as part of general and administrative expenses.

“Cash share-based compensation” or “Cash SBC expenses” Share-based compensation that is settled by way of cash payout, as opposed to equity settled.

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“Reinvestment rate” Comparing the amount of our capital spending to adjusted funds flow (as a percentage).

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INTERNAL CONTROLS AND PROCEDURES

We are required to comply with National Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings. This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to Enerplus’ internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended March 31, 2023.

ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our Annual Information Form, is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

FORWARD-LOOKING INFORMATION AND STATEMENTS

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This MD&A 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 MD&A contains forward-looking information pertaining to the following: expectations regarding Enerplus’ business, operations and financial condition in 2023 and beyond; Enerplus’ return of capital plans, including expectations regarding payment of dividends and the source of funds related thereto; expectations regarding Enerplus’ share repurchase program, including timing and amounts thereof, the anticipated renewal of the Company’s NCIB and timing thereof and the funding of the share repurchase program from free cash flow; expected production volumes in 2023, including the production mix, and 2023 production guidance; 2023 capital spending guidance; expectations regarding free cash flow generation and long-term capital spending reinvestment rates; expected operating strategy in 2023; the proportion of our anticipated crude oil and natural gas liquids production that is hedged and the expected effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; oil and natural gas prices and differentials and expectations regarding the market environment and our commodity risk management program in 2023; 2023 Bakken and Marcellus differential guidance; expectations regarding realized oil and natural gas prices; expected operating, transportation and cash G&A expenses and production taxes and 2023 guidance with respect thereto; potential future non-cash PP&E impairments, as well as relevant factors that may affect such impairment; the amount of our future abandonment and reclamation costs and asset retirement obligations; deferred income taxes and the time at which cash taxes may be paid; expected 2023 cash tax as a percentage of adjusted funds flow before tax; future debt and working capital levels, financial capacity, liquidity and capital resources to fund capital spending, working capital requirements and deficits and senior note repayments; expectations regarding our ability to comply with or renegotiate debt covenants under the Bank Credit Facilities and outstanding senior notes; and our future acquisitions and dispositions.

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The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: the ability to fund our return of capital plans, including both dividends at the current level and the share repurchase program, from free cash flow as expected; that our common share trading price will be at levels, and that there will be no other alternatives, that, in each case, make share repurchases an appropriate and best strategic use of our free cash flows; that we will conduct our operations and achieve results of operations as anticipated; the continued operation of DAPL; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and anticipated commodity prices, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions, the impact of inflation, weather conditions, storage fundamentals; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; our ability to comply with our debt covenants; our ability to meet the targets associated with the Bank Credit Facilities; the availability of third party services; expected transportation costs; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement obligations; factors used to assess the realizability of our deferred income tax assets; and the availability of technology and process to achieve environmental targets.

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In addition, our 2023 guidance described in this MD&A is based on: a WTI price of $80.00/bbl, a NYMEX price of $3.00/Mcf, a Bakken crude oil price differential of $0.50/bbl above WTI, a Marcellus natural gas price differential of $0.75/Mcf below NYMEX and a CDN/USD exchange rate of $0.74. 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. Current conditions, economic and otherwise, render assumptions, although reasonable when made, subject to increased uncertainty.

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The forward-looking information included in this MD&A 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 by Enerplus to achieve or realize anticipated proceeds or benefits, of the sale of Enerplus’ assets in Canada; continued instability, or further deterioration, in global economic and market environment, inflation and/or the Ukraine/Russia conflict and heightened geopolitical risks; decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus’ products from those currently anticipated; changes in the demand for or supply of our products, including global energy demand; volatility in our common share trading price and free cash flow that could impact our planned share repurchases and dividend levels; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings or other events inhibiting or preventing operation of DAPL; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; risks associated with the realization of our deferred income tax assets; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our Bank Credit Facilities and/or outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; changes in law or government programs or policies in Canada or the United States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in this MD&A, our Annual Information Form, our Annual MD&A and Form 40-F at December 31, 2022), which are available at www.sedar.com, www.sec.gov and through Enerplus’ website at www.enerplus.com.

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The forward-looking information contained in this MD&A speaks only as of the date of this MD&A. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws. Any forward-looking information contained herein are expressly qualified by this cautionary statement.

        STATEMENTS

Exhibit 99.2

Condensed Consolidated Balance Sheets

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