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Enerplus announces first quarter 2021 results; increases and transitions to a quarterly dividend

May 6, 2021 2:30 PM
CNW

All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under “Non-GAAP Measures”. This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the “Forward-Looking Information and Statements” at the conclusion of this news release. A full copy of Enerplus’ First Quarter 2021 Financial Statements and MD&A will be available on the Company’s website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.

CALGARY, AB – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today announced financial and operating results for the first quarter of 2021 and an increase to its dividend. The Company reported first quarter 2021 cash flow from operating activities and adjusted funds flow of $37.2 million and $128.0 million, respectively, compared to $122.7 million and $113.2 million, respectively, in the first quarter of 2020. Cash flow from operating activities decreased from the prior year period primarily due to changes in working capital.  Adjusted funds flow increased from the prior year period primarily due to improved realized commodity prices during the first quarter of 2021.

HIGHLIGHTS

  • Adjusted funds flow was $128.0 million in the first quarter, which exceeded capital spending of $65.5 million, generating free cash flow of $62.5 million
  • Delivered first quarter production of 91,671 BOE per day, including liquids of 49,046 barrels per day
  • Completed two accretive acquisitions in the Williston Basin year to date, increasing Enerplus’ acreage position in North Dakota by over four times to 296,000 net acres and extending its high-return development inventory
  • Expect to deliver a 20% total well cost reduction in North Dakota in 2021 compared to 2019 through continued technology application and innovation
  • Maintaining a solid financial position: net debt to adjusted funds flow ratio expected to be 1.3x or less by year-end 2021 based on US$55 per barrel WTI (annualized for 2021 acquisitions); current undrawn capacity on bank credit facility of approximately US$750 million
  • Increasing the dividend and transitioning to quarterly payments: new quarterly dividend of $0.033 per share, a 10% increase from the current monthly dividend of $0.01 per share on an annualized basis, will be payable on June 15, 2021 to shareholders of record on May 28, 2021. Given the April and May dividends have already been paid or declared, the change to quarterly payments beginning in June represents an incremental dividend payment of $5.6 million in the second quarter of 2021

“It has been a constructive start to the year for us, having announced and closed two strategic acquisitions in the Bakken,” said Ian C. Dundas, President and CEO. “These acquisitions are expected to be highly accretive to our per share metrics, support continued operational efficiencies and extend our core Bakken development inventory. They are also helping to drive a step change in the free cash flow generation of our business. As a result, and consistent with our commitment to sustainably growing our return of capital to shareholders, we are increasing our dividend.  As we continue integration efforts, we remain focused on delivering safe, consistent execution under a disciplined capital allocation framework.”

FIRST QUARTER SUMMARY

Production in the first quarter of 2021 was 91,671 BOE per day, a decrease of 7% compared to the same period a year ago, and 6% higher than the prior quarter. Crude oil and natural gas liquids production in the first quarter of 2021 was 49,046 barrels per day, a decrease of 10% compared to the same period a year ago, and approximately flat to the prior quarter. The lower production compared to the same period in 2020 was due to the significant reduction in capital activity in 2020 in response to the low commodity price environment. Quarter-over-quarter production was higher due to increased Marcellus volumes and the contribution of approximately 6,300 BOE per day from the Company’s acquisition of Bruin which closed on March 10, 2021.

Enerplus reported first quarter 2021 net income of $14.7 million, or $0.06 per share, compared to net income of $2.9 million, or $0.01 per share, in the same period in 2020. Adjusted net income for the first quarter of 2021 was $56.3 million, or $0.23 per share, compared to $21.1 million, or $0.09 per share, during the same period in 2020. Net income and adjusted net income were higher compared to the prior year period primarily due to higher benchmark commodity prices and stronger commodity price realizations during the first quarter of 2021.

Enerplus’ first quarter 2021 realized Bakken oil price differential was US$3.12 per barrel below WTI, compared to US$5.26 per barrel below WTI in the first quarter of 2020. The improved year-over-year Bakken differential was supported by increased refinery demand in the first quarter of 2021, while regional production was and continues to be lower than pre-pandemic levels.

The Company’s realized Marcellus natural gas price differential was US$0.15 per Mcf below NYMEX during the first quarter of 2021, compared to US$0.38 per Mcf below NYMEX in the first quarter of 2020. Marcellus pricing is generally stronger during the first quarter associated with an increase in seasonal demand due to the onset of colder weather. The Company continues to expect significant seasonality in pricing in the U.S. Northeast moving through the rest of the year.

In the first quarter of 2021, Enerplus’ operating costs were $7.82 per BOE, transportation costs were $3.98 per BOE and cash general and administrative expenses were $1.59 per BOE.

Exploration and development capital spending totaled $65.5 million in the first quarter of 2021. The Company paid $7.4 million in dividends in the quarter.

Enerplus ended the first quarter of 2021 with total debt of $983.2 million and cash of $189.0 million. Subsequent to the first quarter, the Company increased and extended its senior, unsecured bank credit facility to US$900 million (from US$600 million) with a maturity date extended to October 31, 2025.  The Company also transitioned this facility to a sustainability-linked credit facility (“SLL credit facility”), incorporating sustainability-linked performance targets (see the Company’s news release dated April 29, 2021).

ASSET HIGHLIGHTS

Williston Basin production averaged 47,327 BOE per day (73% tight oil), inclusive of production acquired through the Bruin acquisition which closed on March 10, 2021. This is a decrease of 4% compared to the same period a year ago, and 3% higher than the prior quarter. The Company brought three gross operated wells (100% working interest) on production late in the first quarter. The Company reinitiated its drilling program in North Dakota in April and plans to continue running one drilling rig for the rest of the year. Enerplus is continuing to drive strong well cost efficiencies, with the average cost for a two-mile lateral expected to decline to US$6.1 million in 2021, a 20% reduction compared to 2019.

Marcellus production averaged 204 MMcf per day during the first quarter of 2021, a decrease of 6% compared to the same period in 2020, and 16% higher than the prior quarter. The Company participated in drilling 14 gross non-operated wells (1% average working interest) and brought 16 gross non-operated wells (3% average working interest) on production during the quarter.

Canadian waterflood production averaged 7,383 (97% oil) during the first quarter of 2021, a decrease of 10% compared to the same period in 2020, and 4% lower than the prior quarter.

In the DJ Basin, Enerplus brought three gross operated wells (86% average working interest) on production during the first quarter.

ACQUISITIONS UPDATE

Enerplus announced two strategic acquisitions in the Williston Basin year to date, which are expected to deliver meaningful accretion to per share metrics, enhance the Company’s free cash flow outlook, extend its high-return drilling inventory and support further operational efficiencies.

The Company’s acquisition of Bruin for total cash consideration of US$465 million (prior to closing adjustments), closed on March 10, 2021. The Company’s acquisition of assets from Hess Corporation for total cash consideration of US$312 million (prior to closing adjustments), closed on April 30, 2021. Enerplus continues to maintain excellent liquidity and had approximately US$750 million undrawn capacity on its US$900 million SLL credit facility at May 1, 2021.

DIVIDEND INCREASE; QUARTERLY PAYMENTS

Enerplus’ Board of Directors approved a 10% increase to the Company’s dividend to $0.033 per share paid quarterly, from $0.01 per share paid monthly previously. The first increased quarterly dividend is payable on June 15, 2021 to all shareholders of record at the close of business on May 28, 2021. The ex-dividend date for this payment is May 27, 2021.

2021 GUIDANCE UPDATE

Production and capital spending guidance for 2021 remains unchanged and is summarized in the table below. Capital spending is expected to be split relatively evenly between the first and second half of the year. Approximately 80% of the Company’s 2021 capital budget is allocated to its North Dakota operations where it expects to drill 21 gross (21 net) operated wells and bring 42 gross (32 net) operated wells on production during the year. In addition to this operated activity, the budget includes an allocation for non-operated activity in North Dakota.

Operating expenses in 2021 are expected to average $8.25 per BOE. Unit operating expenses are expected to increase following the first quarter due to the Company’s increased liquids production weighting from its recent acquisitions. Enerplus’ first quarter production was 54% liquids which is expected to increase above 60% liquids for the rest of 2021.

Transportation and cash general and administrative (“G&A”) expenses in 2021 are expected to average $3.85 per BOE and $1.25 per BOE, respectively.

2021 Guidance

Capital spending

$360 to $400 million

Average annual production

111,000 to 115,000 BOE/day

Average annual crude oil and natural gas liquids production

68,500 to 71,500 bbls/day

Average royalty and production tax rate

26%

Operating expense

$8.25/BOE

Transportation expense

$3.85/BOE

Cash G&A expense

$1.25/BOE

2021 Full-Year Differential/Basis Outlook (1)

U.S. Bakken crude oil differential (compared to WTI crude oil)(2)

US$(3.25)/bbl

Marcellus natural gas sales price differential (compared to NYMEX natural gas)

US$(0.55)/Mcf

(1)

Excluding transportation costs.

(2)

Assuming the Dakota Access Pipeline (“DAPL”) continues to operate.

PRICE RISK MANAGEMENT

Enerplus’ latest commodity hedging positions are provided in the table below.

Enerplus’ Financial Commodity Hedging Contracts (As at May 5, 2021)

WTI Crude Oil
(US$/bbl)(1)(2)

NYMEX
Natural Gas
(US$/Mcf)

Apr 1, 2021 –

Jul 1, 2021 –

Jan 1, 2022 –

Jan 1, 2023 –

Nov 1, 2023 –

Apr 1, 2021 –

Jun 30, 2021

Dec 31, 2021

Dec 31, 2022

Oct 31, 2023

Dec 31, 2023

 Oct 31, 2021

Swaps

Volume (bbls/day)

–

–

–

–

–

60,000

Sold Swaps

–

–

–

–

–

$ 2.90

Three Way Collars

Volume (bbls/day)

20,000

23,000

17,000

–

–

40,000

Sold Puts

$ 32.00

$ 36.39

$ 40.00

–

–

$ 2.15

Purchased Puts

$ 40.90

$ 46.39

$ 50.00

–

–

$ 2.75

Sold Calls

$ 50.72

$ 56.70

$ 57.91

–

–

$ 3.25

Hedges acquired from Bruin (3)

Swaps

Volume (bbls/day)

9,750

8,465

3,828

250

–

–

Sold Swaps

$ 42.16

$ 42.52

$ 42.35

$ 42.10

–

–

Collars

Volume (bbls/day)

–

–

–

2,000

2,000

–

Purchased Puts

–

–

–

$ 5.00

$ 5.00

–

Sold Calls

–

–

–

$ 75.00

$ 75.00

–

(1)

The total average deferred premium spent on outstanding hedges is US$0.67/bbl from April 1, 2021 – December 31, 2021 and US$1.22/bbl from January 1, 2022 – December 31, 2022.

(2)

Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(3)

Upon close of the Bruin acquisition, Bruin’s outstanding hedges were recorded at a fair value on the balance sheet. Realized and unrealized gains and losses on the acquired hedges are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of the close of the Bruin acquisition. For the three months ended March 31, 2021, Enerplus recognized an unrealized gain of $17.4 million in the Consolidated Statement of Income/(Loss). The Bruin hedges were in a liability position of $70.9 million at March 31, 2021.

Q1 2021 Conference Call Details

A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) on May 7, 2021 to discuss these results. Details of the conference call are as follows:

Date:

Friday, May 7, 2021

Time:

9:00 AM MT (11:00 AM ET)

Dial-In:

587-880-2171 (Alberta)

1-888-390-0546 (Toll Free)

Conference ID:

35089571

Audiocast:   

https://produceredition.webcasts.com/starthere.jsp?ei=1450753&tp_key=6e8d1a2524

To ensure timely participation in the conference call, callers are encouraged to join 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:

Replay Dial-In:

1-888-390-0541 (Toll Free)

Replay Passcode:

089571 #

Summary of Average Daily Production(1)

Three months ended March 31, 2021

Williston Basin

Marcellus

Canadian
Waterfloods

Other(2)

Total

Tight oil (bbl/d)

34,489

–

–

787

35,275

Light & medium oil (bbl/d)

–

–

3,040

32

3,072

Heavy oil (bbl/d)

–

–

4,108

9

4,118

Total crude oil (bbl/d)

34,489

–

7,149

828

42,465

Natural gas liquids (bbl/d)

5,993

–

26

562

6,581

Shale gas (Mcf/d)

41,069

203,985

–

1,136

246,191

Conventional natural gas (Mcf/d)

–

–

1,255

8,303

9,558

Total natural gas (Mcf/d)

41,069

203,985

1,255

9,439

255,748

Total production (BOE/d)

47,327

33,998

7,383

2,964

91,671

(1)

Table may not add due to rounding.

(2)

Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Drilled(1)

Three months ended March 31, 2021

Operated

Non-Operated

Gross

Net

Gross

Net

Williston Basin

–

–

–

–

Marcellus

–

–

14

0.2

Canadian Waterfloods

–

–

–

–

Other(2)

–

–

2

0.3

Total

–

–

16

0.5

(1)

Table may not add due to rounding.

(2)

Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Brought On-Stream(1)

Three months ended March 31, 2021

Operated

Non-Operated

Gross

Net

Gross

Net

Williston Basin

3

3.0

–

–

Marcellus

–

–

16

0.4

Canadian Waterfloods

–

–

–

–

Other(2)

3

2.6

2

0.3

Total

6

5.6

18

0.7

(1)

Table may not add due to rounding.

(2)

Comprises DJ Basin and non-core properties in Canada.

SELECTED FINANCIAL RESULTS

Three months ended
March 31, 

2021

2020

Financial (CDN$, thousands, except ratios)

Net Income/(Loss)

$

14,697

$

2,876

Adjusted Net Income/(Loss)(1)

56,251

21,089

Cash Flow from Operating Activities

37,239

122,739

Adjusted Funds Flow(1)

128,048

113,227

Dividends to Shareholders – Declared

7,365

6,670

Total Debt Net of Cash(1)

794,170

514,620

Capital Spending

65,531

163,625

Property and Land Acquisitions

628,568

2,256

Property Divestments

4,995

5,578

Net Debt to Adjusted Funds Flow Ratio(1)(2)

2.1x

0.8x

Financial per Weighted Average Shares Outstanding

Net Income /(Loss) – Basic

$

0.06

$

0.01

Net Income/(Loss) – Diluted

0.06

0.01

Weighted Average Number of Shares Outstanding (000’s) – Basic

244,066

222,357

Weighted Average Number of Shares Outstanding (000’s) – Diluted

246,898

223,300

Selected Financial Results per BOE(3)(4)

Crude Oil & Natural Gas Sales(5)

$

43.55

$

31.96

Royalties and Production Taxes

(10.66)

(8.16)

Commodity Derivative Instruments

(2.35)

3.69

Operating Expenses

(7.82)

(8.84)

Transportation Costs

(3.98)

(3.95)

Cash General and Administrative Expenses

(1.59)

(1.37)

Cash Share-Based Compensation

(0.33)

0.31

Interest, Foreign Exchange and Other Expenses

(1.30)

(0.97)

Adjusted Funds Flow(1)

$

15.52

$

12.67

 

SELECTED OPERATING RESULTS

Three months ended

March 31,

2021

2020

Average Daily Production(4)

Crude Oil (bbls/day)

42,465

49,044

Natural Gas Liquids (bbls/day)

6,581

5,346

Natural Gas (Mcf/day)

255,749

262,913

Total (BOE/day)

91,671

98,209

% Crude Oil and Natural Gas Liquids

54%

55%

Average Selling Price (4)(5)

Crude Oil (per bbl)

$

67.34

$

51.30

Natural Gas Liquids (per bbl)

36.17

12.72

Natural Gas (per Mcf)

3.48

2.08

Net Wells Drilled

1

34

(1)

These non–GAAP measures may not be directly comparable to similar measures presented by other entities. See “Non–GAAP Measures” section in this news release.

(2)

Ratio does not include trailing Adjusted Funds Flow from the Bruin Acquisition.

(3)

Non–cash amounts have been excluded.

(4)

Based on Company interest production volumes. See “Presentation of Production Information” section in this news release.

(5)

Before transportation costs, royalties and the effects of commodity derivative instruments.

Condensed Consolidated Balance Sheets

 

(CDN$ thousands) unaudited

March 31, 2021

December 31, 2020

Assets

Current Assets

Cash and cash equivalents

$

189,016

$

114,455

Accounts receivable

208,742

106,376

Derivative financial assets

4,785

3,550

Other current assets

5,918

7,137

408,461

231,518

Property, plant and equipment:

Oil and natural gas properties (full cost method)

1,237,659

575,559

Other capital assets, net

19,827

19,524

Property, plant and equipment

1,257,486

595,083

Right-of-use assets

32,173

32,853

Deferred income tax asset

593,348

607,001

Total Assets

$

2,291,468

$

1,466,455

Liabilities

Current liabilities

Accounts payable

$

290,808

$

251,822

Dividends payable

2,568

2,225

Current portion of long-term debt

102,506

103,836

Derivative financial liabilities

118,944

19,261

Current portion of lease liabilities

13,765

13,391

528,591

390,535

Derivative financial liabilities

39,720

—

Long-term debt

880,680

386,586

Asset retirement obligation

156,734

130,208

Lease liabilities

22,227

23,446

1,099,361

540,240

Total Liabilities

1,627,952

930,775

Shareholders’ Equity

Share capital – authorized unlimited common shares, no par value

Issued and outstanding: March 31, 2021 – 257 million shares

3,236,117

3,096,969

December 31, 2020 – 223 million shares

Paid-in capital

36,305

50,604

Accumulated deficit

(2,924,685)

(2,932,017)

Accumulated other comprehensive income/(loss)

315,779

320,124

663,516

535,680

Total Liabilities & Shareholders’ Equity

$

2,291,468

$

1,466,455

 

Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)

Three months ended

March 31, 

(CDN$ thousands, except per share amounts) unaudited

2021

2020

Revenues

Crude oil and natural gas sales, net of royalties

$

288,801

$

228,127

Commodity derivative instruments gain/(loss)

(69,843)

131,341

218,958

359,468

Expenses

Operating

64,522

79,020

Transportation

32,823

35,329

Production taxes

17,452

15,444

General and administrative

16,272

19,185

Depletion, depreciation and accretion

46,460

95,192

Asset impairment

4,300

—

Interest

6,823

8,911

Foreign exchange (gain)/loss

122

(5,637)

Transaction costs and other expense/(income)

4,524

(229)

193,298

247,215

Income/(Loss) before taxes

25,660

112,253

Current income tax expense/(recovery)

—

27

Deferred income tax expense/(recovery)

10,963

109,350

Net Income/(Loss)

$

14,697

$

2,876

Other Comprehensive Income/(Loss)

Unrealized gain/(loss) on foreign currency translation

(12,867)

131,774

Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt

8,522

(50,062)

Total Comprehensive Income/(Loss)

$

10,352

$

84,588

Net income/(Loss) per share

Basic

$

0.06

$

0.01

Diluted

$

0.06

$

0.01

Condensed Consolidated Statements of Cash Flows

Three months ended

March 31, 

(CDN$ thousands) unaudited

2021

2020

Operating Activities

Net income/(loss)

$

14,697

$

2,876

Non-cash items add/(deduct):

Depletion, depreciation and accretion

46,460

95,192

Asset impairment

4,300

—

Changes in fair value of derivative instruments

49,842

(96,428)

Deferred income tax expense/(recovery)

10,963

109,350

Foreign exchange (gain)/loss on debt and working capital

319

(2,415)

Share-based compensation and general and administrative

1,842

7,755

Amortization of debt issuance costs

73

—

Translation of U.S. dollar cash held in Canada

(448)

(3,103)

Asset retirement obligation expenditures

(7,080)

(10,794)

Changes in non-cash operating working capital

(83,729)

20,306

Cash flow from/(used in) operating activities

37,239

122,739

Financing Activities

Bank term loan

501,286

—

Proceeds from the issuance of shares

125,746

—

Purchase of common shares under Normal Course Issuer Bid

—

(2,536)

Share-based compensation – cash settled (tax withholding)

(4,491)

(7,232)

Dividends

(7,019)

(6,661)

Cash flow from/(used in) financing activities

615,522

(16,429)

Investing Activities

Capital and office expenditures

(51,762)

(129,342)

Bruin acquisition

(528,597)

—

Property and land acquisitions

(3,407)

(2,256)

Property divestments

4,995

5,578

Cash flow from/(used in) investing activities

(578,771)

(126,020)

Effect of exchange rate changes on cash and cash equivalents

571

10,137

Change in cash and cash equivalents

74,561

(9,573)

Cash and cash equivalents, beginning of period

114,455

151,649

Cash and cash equivalents, end of period

$

189,016

$

142,076

[expand title=”Advisories & Contact”]Currency and Accounting Principles

All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under “Non-GAAP Measures”.

Barrels of Oil Equivalent

This news release also contains references to “BOE” (barrels of oil equivalent), “MBOE” (one thousand barrels of oil equivalent), and “MMBOE” (one million barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs.  BOE, MBOE and MMBOE may be misleading, particularly if used in isolation.  The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.

Presentation of Production Information

Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian disclosure requirements and industry practice, oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. All production volumes and oil and gas sales presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest. All references to “liquids” in this news release include light and medium crude oil, heavy oil and tight oil (all together referred to as “crude oil”) and natural gas liquids on a combined basis.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws (“forward-looking information”). The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “guidance”, “believes” and “plans” and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected benefits of the Hess asset and Bruin acquisition; expected impact of the Hess asset and Bruin acquisitions on Enerplus’ operations and financial results; anticipated impact of the Hess asset and Bruin acquisitions on Enerplus’ future costs and expenses; expectations regarding the duration and overall impact of COVID-19; expected capital spending levels in 2021 and in the future, timing thereof; and the impact thereof on our production levels and land holdings; expected production volumes and 2021 and future production guidance; expected operating strategy in 2021; 2021 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the expected effectiveness of such hedges in protecting our adjusted funds flow in 2021 and the future; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, our commodity risk management program in 2021 and expected hedging gains; expectations regarding our realized oil and natural gas prices; expected operating, transportation, cash G&A and financing costs; expected reduction in well costs; future royalty rates on our production and future production taxes; net debt to adjusted funds-flow ratio, financial capacity and liquidity and capital resources to fund capital spending, dividends and working capital requirements; expectations regarding payment of increased dividends.

The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated, including considering the Hess asset and Bruin acquisition; that our development plans will achieve the expected results; that a lack of adequate infrastructure and/or low commodity price environment will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and estimated commodity prices, differentials and cost assumptions; the continued ability to operate DAPL and lack of court order restricting its operation, that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including expectations regarding the duration and overall impact of COVID-19; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of 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; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to comply with our debt covenants; the availability of third party services; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement obligations; the availability of technology and processes to achieve environmental targets. In addition, Enerplus’ 2021 outlook contained in this news release is based on the following: a WTI price of between US$50 and US$55.00/bbl, a NYMEX price of US$3.00/Mcf, a Bakken crude oil price differential of US$3.25/bbl below WTI and a USD/CDN exchange rate of 1.27. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued instability, or further deterioration, in global economic and market environment, including from COVID-19; continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; failure to realize the anticipated benefits of the Hess asset and Bruin acquisitions; unanticipated operating results, results from our capital spending activities or production declines; the legal proceedings in connection with 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; 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 facility and 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 and contingencies described under “Risk Factors and Risk Management” in Enerplus’ 2020 MD&A and in our other public filings).

The forward-looking information contained in this press release speaks only as of the date of this press release, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

NON-GAAP MEASURES

In this news release, Enerplus uses the terms “adjusted funds flow”, “adjusted net income”, “free cash flow” and “net debt to adjusted funds flow ratio” measures to analyze operating performance, leverage and liquidity. “Adjusted funds flow” is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. “Adjusted net income” is calculated as net income adjusted for unrealized derivative instrument gain/loss, asset impairment, gain on divestment of assets, unrealized foreign exchange gain/loss, and the tax effect of these items. “Free cash flow” is calculated as adjusted funds flow minus capital spending. “Net debt to adjusted funds flow” is calculated as total debt net of cash, including restricted cash, divided by adjusted funds flow.

Enerplus believes that, in addition to cash flow from operating activities, net earnings and other measures prescribed by U.S. GAAP, the terms “adjusted funds flow”, “adjusted net income”, “free cash flow” and “net debt to adjusted funds flow” are useful supplemental measures as they provide an indication of the results generated by Enerplus’ principal business activities. However, these measures are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under “Non-GAAP Measures” in Enerplus’ 2020 MD&A.

Electronic copies of Enerplus Corporation’s First Quarter 2021 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of the Company’s audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

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