MD&A

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

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The following discussion and analysis of financial results is dated May 8, 2024 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, 2023 (the “Annual Information Form”).

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Information presented in the following MD&A is with respect to Enerplus only and does not give effect to completion of the Arrangement (as defined below under "Overview"). Any forward-looking information and guidance included in the following MD&A is subject to change as a result of completion of the Arrangement.

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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.

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does 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, as applicable, utilizing a conversion on this basis may be misleading as an indication of value. Use of BOE in isolation may be misleading.

In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in the Interim 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.

ADVISORY REGARDING 2024 GUIDANCE

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The following MD&A includes certain corporate guidance of Enerplus with respect to its operations and financial results for the remainder of 2024. Enerplus' outlook and guidance presented in this MD&A does not take into account any impact from the closing of the acquisition of Enerplus by Chord Energy Corporation ("Chord"), as described herein, which is anticipated to occur on May 31, 2024, and as such, the actual results from Enerplus' business and operations in such period may change as a result of the completion of this transaction.

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OVERVIEW

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The Arrangement

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As previously announced, on February 21, 2024, Enerplus entered into an arrangement agreement (the "Arrangement Agreement") with Chord, pursuant to which, upon completion of the acquisition by Chord of all of the issued and outstanding common shares of Enerplus (the "Arrangement"), Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash for each share of Enerplus. Additionally, shortly before and conditional upon closing of the Arrangement, Enerplus intends to declare a dividend to its shareholders that will equalize the amount of quarterly dividends declared by Enerplus (on a per common share basis after taking into account the share exchange ratio of 0.10125 of a Chord share per Enerplus common share) to the quarterly dividends declared by Chord following the companies' respective March 2024 dividends that have a record date prior to closing of the Arrangement.

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The Arrangement will be completed as a plan of arrangement under the Business Corporations Act (Alberta) and is subject to the approval of at least two-thirds of the votes cast by holders of Enerplus shares at a meeting currently scheduled to be held on May 24, 2024 (the “Meeting”). The issuance of shares of Chord stock is subject to the approval of the majority of votes cast by holders of shares of Chord in connection with the transaction, pursuant to the rules of the Nasdaq Global Select Market ("NASDAQ"). The Chord shareholder vote is expected to be held on May 14, 2024.

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The Arrangement is subject to customary closing conditions in the United States and Canada, as well as the approvals by Chord and Enerplus’ shareholders referenced above, the approval of the Court of King's Bench of Alberta, the listing of shares of Chord's stock on NASDAQ and regulatory clearances or approvals. Subject to the foregoing approvals, the Arrangement is expected to close on May 31, 2024. See “Forward-Looking Information and Statements” section in this MD&A.

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Further information about the Arrangement is contained in the management information circular and proxy statement of Enerplus in connection with the Meeting, a copy of which can be found on SEDAR+, EDGAR and Enerplus' website.

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First Quarter 2024 Overview

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Production during the first quarter of 2024 averaged 87,151 BOE/day, a decrease of 16% compared to average production of 103,543 BOE/day in the fourth quarter of 2023. The decrease in production was primarily due to the planned sequencing of our completions program in North Dakota, with no operated wells brought online during the fourth quarter of 2023, lower natural gas production due to price-related production curtailments in the Marcellus, and downtime as a result of severe winter weather in North Dakota during January 2024. We continue to expect annual production for 2024 of approximately 99,000 BOE/day, including approximately 64,000 bbls/day of crude oil and natural gas liquids production.

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Capital spending during the first quarter of 2024 was $126.7 million, compared to $91.5 million during the fourth quarter of 2023, with the majority of the spending focused on our U.S. crude oil properties. The increase in capital spending was due to higher completions activity during the first quarter of 2024. We continue to expect annual capital spending for 2024 of $550 million.

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Our realized Bakken crude oil price differential averaged $2.64/bbl below WTI during the first quarter of 2024, compared to $1.26/bbl below WTI during the fourth quarter of 2023. The weaker realized differential was primarily due to a decline in U.S. refinery utilization in response to seasonally lower demand for crude oil and refined products.

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Our realized Marcellus sales price differential averaged $0.06/Mcf above NYMEX in the first quarter of 2024, compared to $1.20/Mcf below NYMEX in the fourth quarter of 2023. The narrower differential was mainly due to strong regional spot prices during the winter period in the first quarter of 2024.

Operating expenses for the first quarter of 2024 were $102.0 million, or $12.86/BOE, compared to $111.2 million, or $11.67/BOE, during the fourth quarter of 2023. The decrease in total operating expenses was primarily due to lower gas facility and fluid handling costs as a result of lower production in the first quarter of 2024. The increase per BOE was primarily due to a decrease in production in the first quarter of 2024.

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In the first quarter of 2024, cash flow from operating activities and adjusted funds flow¹ decreased to $128.7 million and $173.1 million, respectively, compared to $297.9 million and $240.5 million in the fourth quarter of 2023. The decreases were primarily due to lower production and a decrease in realized crude oil commodity prices. In addition, $7.8 million was recorded to transaction costs related to the Arrangement. Cash flow from operating activities decreased due to working capital changes as our non-cash operating working capital deficit changed by $94.6 million.

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

At March 31, 2024, net debt¹ increased to $140.7 million, compared to $119.3 million at December 31, 2023. Net debt is calculated as total debt of $174.1 million, which was comprised of our senior notes and borrowing on our sustainability linked lending bank credit facilities of $900 million and $365 (together referred to as the “Bank Credit Facilities”), less cash on hand of $33.4 million. At March 31, 2024, a total of $51.5 million was drawn on our Bank Credit Facilities. Our net debt to adjusted funds flow ratio¹ was 0.2x, compared to 0.1x at December 31, 2023.

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RESULTS OF OPERATIONS

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Production

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Production during the first quarter of 2024 averaged 87,151 BOE/day, a decrease of 16% compared to average production of 103,543 BOE/day in the fourth quarter of 2023. The decrease in production was primarily due to the planned sequencing of our completions program in North Dakota, with no operated wells brought online during the fourth quarter of 2023, lower natural gas production due to price-related production curtailments in the Marcellus, and downtime as a result of severe winter weather in North Dakota during January 2024.

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For the three months ended March 31, 2024, total production decreased by 11% compared to the same period in 2023 due to lower natural gas production in the Marcellus mainly due to limited capital investment during 2023 and price-related production curtailments in the Marcellus during the first quarter of 2024.

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Our crude oil and natural gas liquids weighting increased to 65% from 58% for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to strong well performance in North Dakota and a decrease in natural gas production in the Marcellus.

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We continue to expect annual production for 2024 of approximately 99,000 BOE/day, including approximately 64,000 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, 2024 and 2023 are outlined below:

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

Pricing

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

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CRUDE OIL

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During the first quarter of 2024, our realized crude oil sales price averaged $74.54/bbl, a decrease of 3% compared to the fourth quarter of 2023 and in line with the decrease in the average WTI benchmark price over the same period. While average WTI prices were lower during the first quarter of 2024 compared to the fourth quarter of 2023, they strengthened through the quarter due to increasing geopolitical risk in the Middle East, continued production discipline by the Organization of the Petroleum Exporting Countries Plus, and more supportive global economic conditions.

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Our realized Bakken crude oil price differential averaged $2.64/bbl below WTI during the first quarter of 2024, compared to $1.26/bbl below WTI during the fourth quarter of 2023. The weaker realized differential was primarily due to a decline in U.S. refinery utilization in response to seasonally lower demand for crude oil and refined products.

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NATURAL GAS LIQUIDS

Our realized sales price for natural gas liquids averaged $18.21/bbl during the first quarter of 2024 compared to $16.86/bbl during the fourth quarter of 2023. The improved realization was primarily due to higher propane prices driven by elevated winter heating demand with benchmark propane pricing at Conway increasing 23% compared to the fourth quarter of 2023.

NATURAL GAS

Our realized natural gas sales price averaged $1.86/Mcf during the first quarter of 2024, an increase of 13% compared to the fourth quarter of 2023. The NYMEX benchmark price decreased by 22% over the same period. The difference in price realization compared to the benchmark was due to increased regional prices received for both our Bakken and Marcellus natural gas production, with local benchmark pricing outperforming NYMEX pricing.

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Our realized Marcellus sales price differential averaged $0.06/Mcf above NYMEX in the first quarter of 2024 compared to $1.20/Mcf below NYMEX in the fourth quarter of 2023. The narrower differential was mainly due to strong regional spot prices during the winter period in the first quarter of 2024.

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Price Risk Management

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At May 7, 2024, we have hedged 5,000 bbls/day of WTI crude oil price exposure from April 1, 2024 to June 30, 2024. 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 table summarizes Enerplus’ price risk management positions at May 7, 2024:

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ACCOUNTING FOR PRICE RISK MANAGEMENT

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During the three months ended March 31, 2024, no realized gain or loss was recorded on our crude oil contracts, compared to a realized gain of $3.4 million for the same period in 2023. For the three months ended March 31, 2024, a realized gain of $0.7 million was recorded on our natural gas contracts, compared to a realized gain of $30.9 million for the same period in 2023. Realized gains recorded during the three months ended March 31, 2024 were due to commodity prices falling below the swap values on our natural gas 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, 2024, the fair value of our crude oil contracts was in a liability position of $0.4 million (December 31, 2023 – asset position of $3.2 million). There were no natural gas contracts in place at March 31, 2024 and December 31, 2023. For the three months ended March 31, 2024, the change in the fair value of our crude oil contracts resulted in an unrealized loss of $3.5 million compared to an unrealized gain of $3.8 million during the same period in 2023. For the three months ended March 31, 2024, no unrealized gain or loss was recorded on our natural gas contracts, compared to an unrealized loss of $10.1 million during the same period in 2023.

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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, 2024 were $362.0 million, or $45.65/BOE, compared to $413.2 million, or $47.02/BOE, for the same period in 2023. The decrease in crude oil and natural gas sales was primarily due to lower natural gas production in the Marcellus as a result of limited capital investment in 2023, and lower realized commodity prices in the first quarter of 2024.

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Operating Expenses

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For the three months ended March 31, 2024, operating expenses were $102.0 million, or $12.86/BOE, compared to $92.8 million, or $10.56/BOE, for the same period in 2023. The increase was primarily due to higher planned well service activity and a greater proportion of production from North Dakota as a result of limited capital investment and price-related production curtailments in the Marcellus.

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Transportation Costs

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For the three months ended March 31, 2024, transportation costs were $32.5 million, or $4.09/BOE, compared to $37.8 million, or $4.30/BOE, for the same period in 2023. The decrease in transportation costs was primarily due to a higher proportion of total production volumes from areas with lower associated transportation costs.

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Production Taxes

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Production taxes for the three months ended March 31, 2024, were $29.4 million, or 8.1%, compared to $30.1 million, or 7.3%, for the same period in 2023. The increase in total production taxes as a percentage of crude oil and natural gas sales was due to a decrease in natural gas revenues with lower associated production taxes.

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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 unit and, as such, the revenue per unit may not correspond with the average selling price under the “Pricing” section of this MD&A.

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Total netbacks before and after the impact of commodity derivative contracts for the three months ended March 31, 2024 were lower compared to the same period in 2023, due to a decrease in natural gas production and lower realized commodity prices.

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For the three months ended March 31, 2024, crude oil properties accounted for 94% of total netback before commodity derivative contracts, compared to 89% during the same period in 2023. 

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General and Administrative (“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 the three months ended March 31, 2024 were $9.5 million, or $1.20/BOE, compared to $13.0 million, or $1.48/BOE, for the same period in 2023. Total cash G&A expenses decreased due to the deferral of certain spending as a result of the Arrangement.

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SBC can be equity-settled or cash-settled, depending on the underlying plan to which it relates. Cash-settled SBC for the three months ended March 31, 2024, was an expense of $3.4 million, or $0.43/BOE, compared to a recovery of $0.9 million, or $0.10/BOE, for the same period in 2023, and relates to our director plans. The expense in 2024 was due to an increase in Enerplus’ share price from 2023.

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Equity-settled non-cash SBC expense for the three months ended March 31, 2024, was $11.4 million, or $1.44/BOE, compared to $7.5 million or $0.85/BOE, for the same period in 2023. The increase was primarily due to an increase in value for the 2024 long-term incentive plan as well as a higher performance multiplier impact on our Performance Share Units (“PSUs”) compared to the same period in 2023.

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Interest Expense

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For the three months ended March 31, 2024, we recorded a total interest expense of $3.5 million, compared to $4.3 million for the same period in 2023. The decrease was primarily due to lower debt levels during the three months ended March 31, 2024, compared to the same period in 2023.

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At March 31, 2024, $51.5 million was drawn on the Bank Credit Facilities. At March 31, 2024, approximately 70% of our debt was based on fixed interest rates and 30% on floating interest rates (December 31, 2023 – 66% fixed and 34% floating), with a weighted average interest rate of 4.1% and 6.6%, respectively (December 31, 2023 – 4.1% fixed and 6.7% floating).

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

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Capital spending for the three months ended March 31, 2024 totaled $126.7 million, compared to $138.6 million for the same period in 2023. The decrease was primarily due to the timing of our 2024 capital program in North Dakota.

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We continue to expect annual capital spending for 2024 of $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. For the three months ended March 31, 2024, Enerplus recorded DD&A expense of $92.5 million, or $11.66/BOE, compared to $87.1 million or $9.91/BOE for the same period in 2023. The increase was primarily a result of capital spending in 2023 and in the first quarter of 2024 and reserve revisions at December 31, 2023.

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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 our net ownership interest and management’s estimate of 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 $117.6 million at March 31, 2024, compared to $125.5 million at December 31, 2023.

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For the three months ended March 31, 2024, ARO settlements were $10.9 million, compared to $6.8 million during the same period in 2023.

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Income Taxes

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For the three months ended March 31, 2024, we recorded current and deferred tax expense of $2.4 million and $2.6 million respectively, compared to $11.0 million and $23.9 million for the same period in 2023. Both current and deferred tax expense are lower due to lower income. Many factors influence taxable income including future commodity prices, production levels, development activities, capital spending, and overall profitability.

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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, 2024, 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 $131.5 million, and the deferred income tax liability recorded in the U.S. was $118.6 million at March 31, 2024 (December 31, 2023 – $133.0 million deferred income tax asset in Canada and $117.6 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 three months, after which it drops to 3.0x. At March 31, 2024, our senior debt to adjusted EBITDA ratio was 0.2x and our net debt to adjusted funds flow ratio¹ was 0.2x. Although a Non-GAAP 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 our liquidity. Refer to the definitions and footnotes below.

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Net debt¹ at March 31, 2024 increased to $140.7 million, compared to $119.3 million at December 31, 2023. At March 31, 2024, net debt was comprised of our senior notes and Bank Credit Facilities, totaling $174.1 million, less cash on hand of $33.4 million. At March 31, 2024, through our Bank Credit Facilities, we had total credit capacity of $1.3 billion, of which $51.5 million was drawn. 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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During the three months ended March 31, 2024, a total of $29.5 million was returned to shareholders through share repurchases and dividends, compared to $66.6 million for the same period in 2023. During the three months ended March 31, 2024, and prior to Enerplus entering into the Arrangement Agreement with Chord, a total of 1.1 million common shares were repurchased and cancelled under the Normal Course Issuer Bid (“NCIB”) at an average price of $14.37 per share, for total consideration of $16.2 million.

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At March 31, 2024, 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.sedarplus.ca. 

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Dividends

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During the three months ended March 31, 2024, we declared total dividends of $13.3 million, or $0.065 per share, compared to $12.0 million, $0.055 per share for the same period in 2023. The aggregate amount of dividends paid to shareholders has increased compared to the same period in 2023 due to an 18% increase in our quarterly dividend since the first quarter of 2023.

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Subsequent to March 31, 2024, the Board of Directors approved a second quarter dividend of $0.065 per share to be paid in June 2024. We expect to fund the dividend through free cash flow generated by the business.

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

Shareholders’ Capital

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For the three months ended March 31, 2024, a total of 5.1 million units vested pursuant to our treasury-settled LTI plans, including the impact of performance multipliers (2023 – 2.3 million). In total, 3.2 million shares were issued from treasury and $12.8 million was transferred from paid-in capital to share capital (2023 – 1.3 million shares; $7.2 million). The required tax withholdings totaled $29.6 million (2023 – $16.4 million). 

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During the three months ended March 31, 2024, and prior to Enerplus entering into the Arrangement Agreement with Chord, 1.1 million common shares were repurchased and cancelled under the NCIB at an average price of $14.37 per share, for total consideration of $16.2 million. Of the amount paid, $10.5 million was charged to share capital and $5.7 million was added to accumulated deficit.

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At March 31, 2024, 11.3 million common shares remain available for repurchase under the current NCIB. Under the terms of the Arrangement Agreement, Enerplus is restricted from repurchasing any common shares under the current NCIB or otherwise, subject to limited exceptions.

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At May 7, 2024, we had 204,246,025 common shares outstanding. In addition, an aggregate of 4,631,472 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.

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QUARTERLY FINANCIAL INFORMATION
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Crude oil and natural gas sales decreased to $362.0 million during the first quarter of 2024, compared to $437.1 million during the fourth quarter of 2023. We reported net income of $66.1 million during the first quarter of 2024 compared to net income of $116.7 million during the fourth quarter of 2023. The decrease in crude oil and natural gas sales and net income in the first quarter of 2024 was primarily due to lower production and lower realized crude oil prices. Net income was further impacted by total commodity derivative instrument losses recorded in the first quarter of 2024 compared to commodity derivative gains recorded in the fourth quarter of 2023 and $7.8 million recorded in transaction costs related to the Arrangement with Chord.

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Crude oil and natural gas sales and net income decreased in 2023, compared to 2022, due to weaker realized pricing.

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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, 2023.

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NON-GAAP AND OTHER FINANCIAL MEASURES

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Non-GAAP Measures

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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 funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing Enerplus’ ability to generate funds to repay debt, pay dividends, and fund future capital investment. 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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“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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“Net debt” is used by Enerplus and is useful for investors and securities analysts in analyzing overall leverage and financial position at the end of the period. 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. There is no directly comparable GAAP equivalent for this measure.

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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.

^{(1) See net debt reconciliation above.}​

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“Netback before impact of commodity derivative contracts” and “Netback after impact of commodity derivative contracts” are used by Enerplus and are 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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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, property and land acquisitions and divestments, and non-cash investing working capital.

“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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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, 2024.

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ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our Annual Information Form, is available under our profile on the SEDAR+ website at www.sedarplus.ca, 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 2024; Enerplus’ expectations regarding payment of dividends and the source of funds related thereto; expected production volumes in 2024, including the production mix, and 2024 production guidance; 2024 capital spending guidance; expected operating strategy in 2024; 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; expectations regarding realized oil and natural gas prices; expectations regarding deferred income tax assets and liabilities; and the amount of our future abandonment and reclamation costs and asset retirement obligations. In addition to the foregoing, this MD&A contains forward-looking information about the Arrangement, including the following: the satisfaction of the conditions to closing of the Arrangement, including the timely receipt of required shareholder, court, regulatory and stock exchange approvals, as required; the ability to complete the Arrangement on the current terms and anticipated timing thereof; and the declaration of an additional dividend to Enerplus shareholders and the amount and timing thereof.

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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: 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 first 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. In addition, this MD&A contains certain expectations and assumptions regarding the Arrangement, including: the ability of Enerplus and Chord to satisfy the conditions to closing of the Arrangement in a timely manner and substantially on the terms as at the date hereof; and that all required regulatory, stock exchange, court and shareholder approvals can be obtained on the necessary terms and in a timely manner.

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In addition, our production and capital expenditures 2024 guidance described in this MD&A is based on rest of year commodity prices of: a WTI price of $80.00/bbl, a NYMEX price of $2.50/Mcf, and a CDN/USD exchange rate of $0.72.  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: continued instability, or further deterioration, in global economic and market environment, inflation and/or the conflicts in Ukraine and the Middle East 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; 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 first 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 first 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, 2023), which are available at www.sedarplus.ca, www.sec.gov and through Enerplus’ website at www.enerplus.com. In addition, in relation to the Arrangement: Enerplus and Chord may not receive or obtain, in a timely manner or at all, the necessary approvals and other conditions required in connection with the Arrangement, including shareholder approvals, regulatory approvals, stock exchange approvals and court approval, and, as a result, the Arrangement may not be completed in a timely manner or at all. See Enerplus' management information circular and proxy statement dated April 23, 2024.

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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. In addition, this MD&A includes certain corporate guidance of Enerplus with respect to its operations and financial results for the remainder of 2024. Enerplus' outlook and guidance presented in this MD&A does not take into account any impact from the closing of the Arrangement, which is anticipated to occur on May 31, 2024, and as such, the actual results from Enerplus' business and operations in such period may change as a result of the completion of the Arrangement.