Sign Up for FREE Daily Energy News
 
BREAKING NEWS:
WEC - Western Engineered Containment
Copper Tip Energy Services
Hazloc Heaters
Copper Tip Energy
WEC - Western Engineered Containment
Hazloc Heaters

Enerplus Announces Fourth Quarter and Full Year 2020 Financial and Operating Results and 2020 Year End Reserves


All financial information contained within this news release has been prepared in accordance with U.S. GAAP. 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. Readers are also referred to “Information Regarding Reserves, Resources and Operational Information”, “Notice to U.S. Readers” and “Non-GAAP Measures” at the end of this news release for information regarding the presentation of the financial, reserves, contingent resources and operational information in this news release, as well as the use of certain financial measures that do not have standard meaning under U.S. GAAP. A copy of Enerplus’ 2020 Financial Statements and MD&A is available on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov. All amounts in this news release are stated in Canadian dollars unless otherwise specified.

CALGARY, ABFeb. 19, 2021 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported fourth quarter 2020 cash flow from operating activities and adjusted funds flow of $96.1 million and $91.9 million, respectively, compared to $188.5 million and $178.9 million, respectively, in the fourth quarter of 2019.  Full year 2020 cash flow from operating activities and adjusted funds flow was $446.4 million and $358.2 million, respectively, compared to $694.2 million and $709.0 million, respectively, in 2019. Cash flow from operating activities and adjusted funds flow decreased from 2019 due to lower benchmark crude oil prices and reduced production volumes.

FULL YEAR 2020 SUMMARY AND ANNOUNCED ACQUISITION

  • Generated free cash flow in 2020  Adjusted funds flow was $358.2 million in 2020, which exceeded capital spending of $291.4 million, generating free cash flow of $66.8 million.

  • Enhanced free cash flow outlook – Upon closing of the recently announced acquisition of Bruin E&P HoldCo, LLC (“Bruin”), anticipated in early March 2021, Enerplus expects to see a material increase in its free cash flow generation. Pro forma and based on a ten-month contribution from Bruin’s assets in 2021, Enerplus expects to generate over $300 million of free cash flow in 2021 based on US$55 per barrel WTI crude oil and US$3.00 per Mcf NYMEX natural gas prices.

  • Maintaining a solid balance sheet – Despite the low commodity price environment in 2020, Enerplus ended the year with a net debt to adjusted funds flow ratio of 1.0x and was undrawn on its US$600 million bank credit facility. Pro forma for the announced acquisition of Bruin, including the associated equity and term facility financings, Enerplus expects to remain in a resilient financial position with excellent liquidity. Enerplus estimates its year end 2021 net debt to adjusted funds flow ratio to be approximately 1.0x based on US$55 per barrel WTI crude oil and US$3.00 per Mcf NYMEX natural gas prices.

  • Business resilience and safe operations – Enerplus successfully adapted to new remote working practices and enhanced safety measures due to the COVID-19 pandemic; achieving the best safety performance in the Company’s history based on lost time injury frequency.

  • Capital efficiency improvement – Solid operational execution delivered a step change in well cost performance in North Dakota with a 17% reduction (US$1.3 million per well) year-over-year. Proved plus probable finding and development (“F&D”) costs were $6.50 per BOE in 2020, over 40% lower than the Company’s prior three year average.

  • Strong performance relative to environmental targets – Reduced 2020 greenhouse gas (“GHG”) emissions intensity by more than 20% year-over-year based on preliminary estimates (target reduction was 10%). Reduced 2020 freshwater use per well completion in North Dakota by 23% year-over-year (target reduction was 15%).

“I want to thank our workforce for their efforts in the face of a challenging 2020,” said Ian C. Dundas, President and CEO of Enerplus. “Their commitment to keeping each other and our communities safe as we adapted to a complicated new environment battling the spread of COVID-19 was exceptional. It was also critical to ensuring the continuity of our operations.”

“Despite the volatile market conditions in 2020, we were able to preserve shareholder value, maintain our strong financial footing and position the business to deliver differentiated shareholder returns going forward. Our announced acquisition of Bruin, expected to close in early March 2021, demonstrates our ongoing commitment to value creation for shareholders, enabling us to accelerate free cash flow growth and further support our focus on providing long term sustainable returns.”

FOURTH QUARTER 2020 SUMMARY

Enerplus delivered fourth quarter production at the high end of its guidance ranges with total production of 86,244 BOE per day (guidance was 84,000 to 87,000 BOE per day), including crude oil and natural gas liquids production of 49,195 barrels per day (guidance was 47,000 to 49,000 barrels per day). Total production in the fourth quarter was 5% lower than the prior quarter and 20% lower than same period in 2019.  Liquids production in the fourth quarter of 2020 was 6% lower than the prior quarter and 18% lower than same period in 2019. The lower quarter-over-quarter production was due to limited capital activity. The lower production compared to the same period in 2019 was due to the significant reduction in capital activity in North Dakota during 2020 in response to the decline in crude oil prices, as well as lower capital activity in the Company’s Marcellus natural gas asset during 2020.

Enerplus reported a fourth quarter 2020 net loss of $204.2 million, or ($0.92) per share, compared to a net loss of $429.1 million, or ($1.93) per share, in the fourth quarter of 2019. The reduced net loss was primarily due to lower non-cash impairment charges in the fourth quarter of 2020. The Company recognized a $311.2 million non-cash property, plant and equipment (“PP&E”) impairment in the fourth quarter of 2020 due to the low commodity price environment and the use of 12-month trailing prices to test for impairment under the Securities and Exchange Commission (“SEC”) guidelines. Excluding the PP&E impairment and certain other non-cash or non-recurring items, fourth quarter 2020 adjusted net income was $22.1 million, or $0.10 per share, compared to $34.4 million, or $0.15 per share, during the same period in 2019. Adjusted net income decreased from the fourth quarter of 2019 due to lower benchmark crude oil prices and reduced production volumes.

Enerplus’ fourth quarter 2020 Bakken crude oil price differential was US$4.82 per barrel below WTI, compared to US$4.40 per barrel below WTI for the same period in 2019. The weaker differential compared to the prior year period was due to the narrowing of Brent-WTI differentials. Enerplus’ fourth quarter Marcellus natural gas price differential was US$1.07 per Mcf below NYMEX, compared to US$0.63 per Mcf below NYMEX for the same period in 2019. Regional pricing in the Marcellus was particularly weak from September to November of 2020 due to nearly full regional storage combined with low demand due to mild weather.

Operating expenses in the fourth quarter of 2020 were $8.20 per BOE, compared to $8.05 per BOE in the same period in 2019. The increase in per unit operating expenses was due to lower production in the fourth quarter of 2020. Cash general and administrative (“G&A”) expenses were $1.46 per BOE in the fourth quarter of 2020, compared to $1.34 per BOE in the prior year period. The increase in per unit G&A expenses was also due to lower production in the fourth quarter of 2020.

Exploration and development capital spending totaled $52.4 million in the fourth quarter of 2020. The Company paid $6.7 million in dividends during the quarter.

Enerplus ended the fourth quarter of 2020 with total debt net of cash of $376.0 million and was undrawn on its US$600 million bank credit facility. The Company’s net debt to adjusted funds flow ratio was 1.0 times at quarter-end.

FULL YEAR 2020 SUMMARY

Enerplus delivered 2020 production at the high end of its annual guidance ranges with total production of 90,697 BOE per day (guidance was 90,000 to 91,000 BOE per day), including crude oil and natural gas liquids production of 51,054 barrels per day (guidance was 50,500 to 51,000 barrels per day). Total production and liquids production decreased 10% and 7%, respectively, compared to 2019. The year-over-year decrease in liquids production was due to the temporary curtailment of crude oil production during the second quarter and the significant reduction in capital activity in North Dakota during 2020 in response to the decline in crude oil prices. Natural gas production decreased 15% year-over-year due to lower capital activity in the Company’s Marcellus natural gas asset during 2020.

Enerplus reported a full year 2020 net loss of $923.4 million, or ($4.15) per share, compared to a net loss of $259.7 million, or ($1.12) per share, in 2019. The higher net loss was primarily due to larger non-cash impairment charges, lower benchmark crude oil prices and reduced production volumes in 2020. The Company recognized non-cash impairments totaling $1,197.6 million in 2020 related to PP&E and goodwill due to the low commodity price environment and the use of 12-month trailing prices to test for impairment under the SEC guidelines. Excluding these impairments and certain other non-cash or non-recurring items, full year 2020 adjusted net income was $19.8 million, or $0.09 per share, compared to $243.2 million, or $1.05 per share, in 2019. Adjusted net income decreased from 2020 due to lower benchmark crude oil prices and reduced production volumes.

Enerplus’ 2020 Bakken crude oil price differential was US$4.96 per barrel below WTI, compared to US$3.61 per barrel below WTI in 2019. The weaker year-over-year differential was due to the significant benchmark oil price volatility and the narrowing of Brent-WTI differentials throughout the year. Enerplus’ 2020 Marcellus natural gas price differential was US$0.65 per Mcf below NYMEX, compared to US$0.39 per Mcf below NYMEX in 2019. Regional pricing in the Marcellus was particularly weak from September to November of 2020 due to nearly full regional storage combined with low demand due to mild weather.

Operating expenses in 2020 were $7.94 per BOE, compared to $7.88 per BOE in 2019. Cash G&A expenses in 2020 were $1.35 per BOE, compared to $1.32 per BOE in 2019.

Exploration and development capital spending totaled $291.4 million in 2020, below the Company’s capital budget guidance of $295 million. The Company paid $26.7 million in dividends in 2020.

2020 YEAR END RESERVES SUMMARY

  • Total proved plus probable (“2P”) reserves were 424.4 MMBOE at year end 2020, 4% lower than year end 2019.

  • Enerplus replaced 50% of total 2020 production, adding 16.7 MMBOE of 2P reserves (including technical revisions and economic factors). In North Dakota, the Company replaced 69% of 2020 production, adding 11.3 MMBOE of 2P reserves.

  • Excluding economic factors, Enerplus replaced 89% of total 2020 production, adding 29.2 MMBOE of 2P reserves. In North Dakota, the Company replaced 119% of 2020 production excluding economic factors, adding 19.4 MMBOE of 2P reserves. Economic factors are reserves revisions due to the significant reduction in year-over-year forecast prices.

  • F&D costs were $26.51 per BOE for proved developed producing (“PDP”) reserves, $6.78 per BOE for proved reserves, and $6.50 per BOE for 2P reserves, including future development costs (“FDC”).

  • Finding, development and acquisition (“FD&A”) costs were $6.97 per BOE for proved reserves and $6.74 per BOE for 2P reserves, including FDC.

ASSET ACTIVITY

Williston Basin production averaged 46,127 BOE per day during the fourth quarter of 2020, 5% lower than the prior quarter and 15% lower than the same period in 2019. Fourth quarter Williston Basin production was comprised of 43,641 BOE per day in North Dakota and 2,486 BOE per day in Montana. In the fourth quarter, the Company brought four operated wells on production (100% working interest). No operated wells were drilled in the fourth quarter. Full year 2020 production from the Williston Basin averaged 47,125 BOE per day, a 3% decrease year-over-year. Enerplus delivered meaningful reductions to its well cost structures in 2020 driven by solid planning and execution coupled with technology application. This led to a continuing trend of improved drilling and completion cycle times resulting in an average total well cost of US$6.3 million in 2020, approximately 17% lower than 2019.

Marcellus shale gas production averaged 175 MMcf per day during the fourth quarter of 2020, 5% lower than the prior quarter and 25% lower than the same period in 2019. In the fourth quarter, the Company participated in drilling 23 gross non-operated wells (7% average working interest) with 19 gross non-operated wells (6% average working interest) brought on production. Full year 2020 production averaged 193 MMcf per day, a 15% decrease year-over-year.

Canadian waterflood production averaged 7,675 BOE per day during the fourth quarter of 2020, approximately flat compared to the prior quarter and 10% lower than the same period in 2019. Full year 2020 production averaged 7,469 BOE per day, a 17% decrease year-over-year.

Summary of Average Daily Production(1)

Three months ended December 31, 2020

Twelve months ended December 31, 2020

Williston
Basin

Marcellus

Canadian
Water-
floods

Other(2)

Total

Williston
Basin

Marcellus

Canadian
Water-
floods

Other(2)

Total

Light & medium oil (bbl/d)

3,167

25

3,192

3,233

43

3,277

Heavy oil (bbl/d)

4,189

28

4,216

3,866

35

3,901

Tight oil (bbl/d)

35,067

930

35,997

37,007

1,236

38,243

Total crude oil (bbl/d)

35,067

7,356

982

43,405

37,007

7,100

1,314

45,421

Natural gas liquids (bbl/d)

5,119

44

627

5,790

4,918

54

661

5,633

Conventional natural gas (Mcf/d)

1,654

8,727

10,381

1,892

10,421

12,314

Shale gas (Mcf/d)

35,644

175,346

922

211,912

31,200

193,002

1,342

225,543

Total natural gas (Mcf/d)

35,644

175,346

1,654

9,649

222,293

31,200

193,002

1,892

11,763

237,857

Total production (BOE/d)

46,127

29,224

7,675

3,218

86,244

47,125

32,167

7,469

3,936

90,697

(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
December 31, 2020

Twelve months ended
December 31, 2020

Operated

Non-Operated

Operated

Non-Operated

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Williston Basin

1

0.4

19

18.8

11

3.0

Marcellus

23

1.6

70

4.8

Canadian Waterfloods

10

10.0

Other(2)

5

4.4

16

0.9

Total

24

1.9

34

33.2

97

8.7

(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
December 31, 2020

Twelve months ended
December 31, 2020

Operated

Non-Operated

Operated

Non-Operated

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Williston Basin

4

4.0

7

1.6

22

20.0

15

3.9

Marcellus

19

1.2

54

2.2

Canadian Waterfloods

10

10.0

Other(2)

2

1.8

1

0.0

Total

4

4.0

26

2.8

34

31.8

70

6.1

(1) Table may not add due to rounding.

(2) Comprises DJ Basin and non-core properties in Canada.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE

Enerplus continued to make strong progress on its ESG initiatives in 2020. Based on preliminary estimates, the Company expects to have reduced its 2020 GHG emissions intensity by more than 20% compared to 2019, an improvement compared to its target reduction of 10%. The Company also reduced its 2020 freshwater use per well completion in North Dakota by 23% compared to 2019, an improvement compared to its target reduction of 15%. Enerplus is finalizing its 2021 environmental targets as it works towards its longer-term goals, including a 50% reduction in GHG emissions intensity by 2030 and a 50% reduction in freshwater use per well completion by 2025.

Enerplus is also on track to achieve its safety targets having delivered a company record in 2020 with a lost time injury frequency (“LTIF”) of 0.08 injuries per 200,000 worker hours, a 66% improvement from 2019. Enerplus is targeting a 25% reduction in LTIF, on average, from 2020 to 2023, relative to its 2019 baseline of 0.24.

BRUIN ACQUISITION AND 2021 GUIDANCE

On January 25, 2021, Enerplus announced that it had entered into a definitive agreement to acquire the equity interest of Bruin, a pure play Williston Basin private company, for total cash consideration of US$465 million, with no assumption of debt and subject to customary closing conditions and purchase price adjustments (the “Bruin Acquisition”). The Bruin Acquisition includes approximately 24,000 BOE per day of existing production and is expected to close in early March 2021. In connection with the Bruin Acquisition, Enerplus entered into a binding commitment letter for a new three-year senior unsecured US$400 million term facility to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the purchase price. Enerplus intends to fund the remaining portion of the purchase price with net proceeds from a $132.3 million bought deal equity financing, which was completed on February 3, 2021.

Assuming completion of the Bruin Acquisition and a ten-month contribution from the Bruin assets to Enerplus’ 2021 results, Enerplus expects to deliver 2021 production of 103,500 to 108,500 BOE per day, including 63,000 to 67,000 barrels per day of liquids. Capital spending in 2021 is expected to be $335 to $385 million.

Pro forma for the Bruin Acquisition, the Company expects to realize a Bakken oil price differential of $3.25 per barrel below WTI in 2021 assuming the Dakota Access Pipeline (“DAPL”) continues to operate. For the Marcellus, Enerplus expects to realize a natural gas price differential of US$0.55 per Mcf below NYMEX in 2021.

Detailed guidance for 2021 will be provided following closing of the Bruin Acquisition.

PRICE RISK MANAGEMENT UPDATE

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

Enerplus’ Financial Commodity Hedging Contracts (As at February 18, 2021)

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

NYMEX Natural Gas
(US$/Mcf)

Jan 1, 2021 –

Apr 1, 2021-

Jul 1, 2021 –

Jan 1 ,2022 –

Mar 1, 2021 –

Apr 1, 2021 –

 Mar 31, 2021

Jun 30, 2021

Dec 31, 2021

 Dec 31, 2022

Mar 31, 2021

Oct 31, 2021

Swaps

Volume (bbls/d or Mcf/d)

5,000

60,000

60,000

Sold Swaps

$ 45.55

$3.16

$ 2.90

Three Way Collars

Volume (bbls/d or Mcf/d)

15,000

20,000

23,000

17,000

40,000

Sold Puts

$ 32.00

$ 32.00

$ 36.39

$ 40.00

$ 2.15

Purchased Puts

$ 40.53

$ 40.90

$ 46.39

$ 50.39

$ 2.75

Sold Calls

$ 50.29

$ 50.72

$ 56.70

$ 57.91

$ 3.25

(1)

The total average deferred premium spent on these hedges is US$0.80/bbl from January 1, 2021 to December 31, 2021 and US$1.50/bbl
from January 1, 2022 to December 31, 2022.

Bruin’s latest commodity hedging positions are provided below, which Enerplus will assume upon close of the Bruin Acquisition.

Bruin’s Financial Commodity Hedging Contracts (As at February 18, 2021)

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

Mar 1, 2021 –

Jan 1, 2022 –

Jan 1, 2023 –

Nov 1, 2023-

Dec 31, 2021

Dec 31, 2022

Oct 31, 2023

Dec 31, 2023

Swaps

Volume (bbls/d)

9,000

3,900

250

Sold Swaps

$ 42.38

$ 42.38

$ 42.10

Collars

Volume (bbls/d)

2,000

2,000

Purchased Puts

$   5.00

$   5.00

Sold Calls

$ 75.00

$ 75.00

(1)

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

(2)

Upon close of the Bruin Acquisition, these hedges will be recorded at fair value on
the Consolidated Balance Sheets. Realized and unrealized gains and losses on the
acquired hedges will be recorded in the Consolidated Statement of Income/(Loss)
and the Consolidated Balance Sheets, respectively, to reflect changes in WTI prices
from the date of the close of the Bruin Acquisition.

SUMMARY FINANCIAL AND OPERATING RESULTS

Three months ended

Twelve months ended

SELECTED FINANCIAL RESULTS

December 31, 

December 31, 

2020

2019

2020

2019

Financial (CDN$, thousands, except ratios)

Net Income/(Loss)

$

(204,167)

$

(429,143)

$

(923,367)

$

(259,720)

Adjusted Net Income(1)

22,149

34,365

19,758

243,160

Cash Flow from Operating Activities

96,079

188,492

446,365

694,240

Adjusted Funds Flow(1)

91,871

178,922

358,160

708,992

Dividends to Shareholders – Declared

6,677

6,656

26,698

27,688

Total Debt Net of Cash(1)

375,967

454,984

375,967

454,984

Capital Spending

52,414

99,389

291,468

618,910

Property and Land Acquisitions

2,061

6,126

10,121

24,406

Property Divestments

47

(316)

6,145

9,583

Net Debt to Adjusted Funds Flow Ratio(1)

1.0x

0.6x

1.0x

0.6x

Financial per Weighted Average Shares Outstanding

Net Income/(Loss) – Basic

$

(0.92)

$

(1.93)

$

(4.15)

$

(1.12)

Net Income/(Loss) – Diluted

(0.92)

(1.93)

(4.15)

(1.12)

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

222,548

222,227

222,503

231,334

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

222,548

222,227

222,503

231,334

Selected Financial Results per BOE(2)(3)

Crude Oil & Natural Gas Sales(4)

$

30.60

$

41.64

$

27.82

$

42.65

Royalties and Production Taxes

(7.67)

(10.93)

(7.12)

(10.88)

Commodity Derivative Instruments

3.12

0.07

3.95

0.42

Operating Expenses

(8.20)

(8.05)

(7.94)

(7.88)

Transportation Costs

(3.89)

(3.82)

(3.99)

(3.93)

General and Administrative Expenses

(1.46)

(1.34)

(1.35)

(1.32)

Cash Share-Based Compensation

(0.11)

0.01

0.04

(0.02)

Interest, Foreign Exchange and Other Expenses

(0.81)

(0.89)

(1.06)

(0.72)

Current Income Tax Recovery

1.41

0.44

0.91

Adjusted Funds Flow(1)

$

11.58

$

18.10

$

10.79

$

19.23

Three months ended

Twelve months ended

SELECTED OPERATING RESULTS

December 31, 

December 31, 

2020

2019

2020

2019

Average Daily Production(3)

Crude Oil (bbls/day)

43,405

54,344

45,421

49,704

Natural Gas Liquids (bbls/day)

5,790

5,502

5,633

4,929

Natural Gas (Mcf/day)

222,293

285,537

237,857

278,451

Total (BOE/day)

86,244

107,436

90,697

101,042

% Crude Oil and Natural Gas Liquids

57%

56%

56%

54%

Average Selling Price(3)(4)

Crude Oil (per bbl)

$

47.95

$

67.23

$

44.35

$

68.98

Natural Gas Liquids (per bbl)

17.19

18.28

10.29

15.19

Natural Gas (per Mcf)

2.04

2.50

1.87

2.87

Net Wells Drilled

2

9

42

56

(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)

Non–cash amounts have been excluded.

(3)

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

(4)

Before transportation costs, royalties and commodity derivative instruments.

INDEPENDENT RESERVES EVALUATION

All of the Company’s reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. Independent reserves evaluations have been conducted on properties comprising approximately 98% of the net present value (discounted at 10%, before tax, using January 1, 2021 forecast prices and costs described below) of the Company’s total 2P reserves.

McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 86% of the net present value (discounted at 10%, before tax, using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2021) of the Company’s 2P reserves located in Canada and all of the  reserves associated with the Company’s properties located in North DakotaMontana and Colorado. The Company has evaluated the remaining 14% of the net present value of its Canadian properties using similar evaluation parameters, including the same forecast price and inflation rate assumptions utilized by McDaniel. McDaniel has reviewed the Company’s internal evaluation of these properties. Netherland, Sewell & Associates (“NSAI”), independent petroleum consultants based in Dallas, Texas, has evaluated all of the Company’s reserves associated with the Company’s properties in Pennsylvania. For consistency in the Company’s reserves reporting, NSAI also used the average commodity price forecasts and inflation rates of McDaniel, GLJ and Sproule as of January 1, 2021 to prepare its report.

The following information sets out Enerplus’ gross and net crude oil, NGLs and natural gas reserves volumes and the estimated net present values of future net revenues associated with such reserves as at December 31, 2020 using forecast price and cost cases, together with certain information, estimates and assumptions associated with such reserves estimates. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit associated with a property. It should be noted that tables may not add due to rounding. The following information does not give effect to the Bruin Acquisition.

Reserves Summary

Reserves Summary

Light &
Medium
Oil
(Mbbls)

Heavy Oil
(Mbbls)

Tight
Oil
(Mbbls)

Total Oil
(Mbbls)

Natural
Gas
Liquids
(Mbbls)

Conventional
Natural Gas
(MMcf)

Shale
Gas

(MMcf)

Total
(MBOE)

Gross

Proved producing

5,884

15,052

51,508

72,444

8,123

17,279

568,258

178,156

Proved developed non-producing

93

2,970

3,063

326

3,918

4,043

Proved undeveloped

660

1,893

51,708

54,261

6,451

74

357,370

120,286

Total proved

6,637

16,946

106,186

129,769

14,900

17,353

929,546

302,485

Total probable

2,383

5,309

63,941

71,633

8,602

5,811

244,388

121,934

Proved plus Probable

9,020

22,254

170,127

201,402

23,501

23,164

1,173,934

424,419

Net

Proved producing

4,894

13,076

41,481

59,451

6,629

17,945

456,831

145,209

Proved developed non-producing

77

2,397

2,474

260

3,194

3,266

Proved undeveloped

563

1,587

41,403

43,553

5,159

63

283,680

96,002

Total proved

5,534

14,663

85,281

105,477

12,048

18,008

743,705

244,478

Total probable

1,906

4,542

51,224

57,672

6,929

5,928

195,781

98,219

Proved plus Probable

7,440

19,204

136,505

163,149

18,977

23,936

939,485

342,697

Reserves Reconciliation

The following tables outline the changes in Enerplus’ proved, probable and proved plus probable reserves, on a gross basis, from December 31, 2019 to December 31, 2020.

Proved Reserves – Gross Volumes (Forecast Prices)

Light &
Medium
 Oil
(Mbbls)

Heavy
Oil
(Mbbls)

Tight
Oil
(Mbbls)

Total Oil
(Mbbls)

Natural
Gas
Liquids
(Mbbls)

Conventional
Natural Gas
(MMcf)

Shale
Gas
(MMcf)

Total
(MBOE)

Proved Reserves at
Dec. 31, 2019

7,770

20,121

112,812

140,703

14,327

24,242

933,737

314,693

Acquisitions

Dispositions

Discoveries

Extensions & improved recovery

12,111

12,111

1,636

76,643

26,521

Economic factors

(465)

(1,082)

(5,668)

(7,215)

(849)

(2,195)

(9,970)

(10,092)

Technical revisions

529

(666)

890

754

1,802

(824)

11,606

4,352

Production

(1,197)

(1,428)

(13,959)

(16,584)

(2,016)

(3,870)

(82,470)

(32,990)

Proved Reserves at
Dec. 31, 2020

6,637

16,946

106,186

129,769

14,900

17,353

929,546

302,485

Probable Reserves – Gross Volumes (Forecast Prices)

Light &
Medium
 Oil
(Mbbls)

Heavy
Oil
(Mbbls)

Tight
Oil
(Mbbls)

Total Oil
(Mbbls)

Natural
Gas
Liquids
(Mbbls)

Conventional
Natural Gas
(MMcf)

Shale
Gas
(MMcf)

Total
(MBOE)

Probable Reserves at
Dec. 31, 2019

2,788

6,470

68,240

77,498

8,396

7,395

233,613

126,061

Acquisitions

Dispositions

Discoveries

Extensions & improved

6,454

6,454

698

38,538

13,576

recovery

Economic factors

11

(506)

(1,537)

(2,032)

(209)

(588)

(975)

(2,501)

Technical revisions

(416)

(655)

(9,216)

(10,287)

(284)

(997)

(26,788)

(15,202)

Production

Probable Reserves at
Dec. 31, 2020

2,383

5,309

63,941

71,633

8,602

5,811

244,388

121,934

Proved Plus Probable Reserves – Gross Volumes (Forecast Prices)

Light &
Medium
 Oil
(Mbbls)

Heavy
Oil
(Mbbls)

Tight
Oil
(Mbbls)

Total Oil
(Mbbls)

Natural
Gas
Liquids
(Mbbls)

Conventional
Natural Gas
(MMcf)

Shale
Gas
(MMcf)

Total
(MBOE)

Proved Plus Probable
Reserves at Dec. 31, 2019

10,558

26,591

181,052

218,201

22,723

31,637

1,167,349

440,755

Acquisitions

Dispositions

Discoveries

Extensions & improved

18,565

18,565

2,335

115,181

40,097

recovery

Economic factors

(454)

(1,589)

(7,205)

(9,248)

(1,058)

(2,783)

(10,946)

(12,593)

Technical revisions

113

(1,320)

(8,326)

(9,533)

1,518

(1,821)

(15,181)

(10,849)

Production

(1,197)

(1,428)

(13,959)

(16,584)

(2,016)

(3,870)

(82,470)

(32,990)

Proved Plus Probable
Reserves at Dec. 31, 2020

9,020

22,254

170,127

201,402

23,501

23,164

1,173,934

424,419

Future Development Costs

Changes in forecast FDC occur annually as a result of development activities, acquisition and divestment activities and capital cost estimates that reflect the evaluators’ best estimate of the capital required to bring the proved and proved plus probable reserves on production. The aggregate of the exploration and development costs incurred in the most recent year and the change during the year in estimated FDC generally reflect the total finding and development costs related to reserves additions for that year.

The following is a summary of the estimated FDC required to bring the total proved and proved plus probable reserves on production:

Future Development Costs

Proved

Reserves

 Proved Plus

Probable Reserves

($ millions)

2021

258

260

2022

314

315

2023

321

344

2024

264

378

2025

34

303

2026

3

277

Remainder

3

6

Total FDC Undiscounted

1,197

1,883

Total FDC Discounted at 10%

989

1,431

F&D and FD&A Costs – including FDC

($ millions except for per BOE amounts)

2020

2019

2018

3 Year

Proved Plus Probable Reserves

Finding & Development Costs

Capital Expenditures

$291.4

$618.9

$593.8

$1,504.1

Net change in Future Development Costs

$(183.2)

$47.0

$309.1

$172.9

Gross Reserves additions (MMBOE)

16.7

51.0

65.7

133.4

F&D costs ($/BOE)

$6.50

$13.05

$13.74

$12.57

Finding, Development & Acquisition Costs

Capital expenditures and net acquisitions

$295.4

$633.7

$612.7

$1,541.8

Net change in Future Development Costs

$(183.2)

$44.0

$308.1

$168.8

Gross Reserves additions (MMBOE)

16.7

49.7

64.1

130.4

FD&A costs ($/BOE)

$6.74

$13.63

$14.37

$13.12

Proved Reserves

Finding & Development Costs

Capital Expenditures

$291.4

$618.9

$593.8

$1,504.1

Net change in Future Development Costs

$(150.5)

$2.4

$309.3

$161.2

Gross Reserves additions (MMBOE)

20.8

54.6

54.1

129.5

F&D costs ($/BOE)

$6.78

$11.37

$16.69

$12.86

Finding, Development & Acquisition Costs

Capital expenditures and net acquisitions 

$295.4

$633.7

$612.7

$1,541.8

Net change in Future Development Costs

$(150.5)

$(0.5)

$308.3

$157.3

Gross Reserves additions (MMBOE)

20.8

53.6

52.9

127.2

FD&A costs ($/BOE)

$6.97

$11.82

$17.42

$13.35

Proved Developed Producing Reserves

Finding & Development Costs

Capital Expenditures

$291.4

$618.9

$593.8

$1,504.1

Gross Reserves additions (MMBOE)

11.0

38.8

45.4

95.1

F&D costs ($/BOE)

$26.51

$15.97

$13.08

$15.81

Forecast Price Assumptions

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2021 (utilized by McDaniel, NSAI and by the Company in its internal evaluations for consistency in the Company’s reserves reporting), and the following inflation and exchange rate assumptions.

WTI
Crude Oil(1)
US$/bbl

Light

Crude Oil(2)
Edmonton 
CDN$/bbl

Alberta
 Heavy
Crude Oil(3)
CDN$/bbl

U.S. Henry
Hub Gas
Price
US$/MMBtu

Exchange
Rate
US$/CDN$

Inflation
Rate

%/year

2021

47.17

55.76

39.87

2.83

0.768

0.0

2022

50.17

59.89

43.20

2.87

0.765

1.3

2023

53.17

63.48

46.86

2.90

0.763

2.0

2024

54.97

65.76

48.67

2.96

0.763

2.0

2025

56.07

67.13

49.65

3.02

0.763

2.0

2026

57.19

68.53

50.65

3.08

0.763

2.0

2027

58.34

69.95

51.67

3.14

0.763

2.0

2028

59.50

71.40

52.71

3.20

0.763

2.0

2029

60.69

72.88

53.76

3.26

0.763

2.0

2030

61.91

74.34

54.84

3.33

0.763

2.0

2031

63.15

75.83

55.94

3.39

0.763

2.0

2032

64.41

77.34

57.05

3.46

0.763

2.0

2033

65.70

78.89

58.20

3.53

0.763

2.0

2034

67.01

80.47

59.36

3.60

0.763

2.0

2035

68.35

82.08

60.55

3.67

0.763

2.0

Thereafter

(4)

(4)

(4)

(4)

0.763

2.0

(1)

West Texas Intermediate at Cushing, Oklahoma 40 degree API / 0.5% Sulphur.

(2)

Edmonton Light Sweet 40 degree API, 0.3% Sulphur.

(3)

Heavy Crude Oil 12 degree API at Hardisty, Alberta (after deducting blending costs to reach
pipeline quality).

(4)

Escalation is approximately 2% per year thereafter.

Net Present Value of Future Production Revenue

The following table provides an estimate of the net present value of Enerplus’ future production revenue after deduction of royalties, estimated future capital and operating expenditures, before income taxes. It should not be assumed that the present value of estimated future cash flows shown below is representative of the fair market value of the reserves.

Net Present Value of Future Production Revenue – Forecast Prices and Costs (before tax)

Reserves at December 31, 2020, ($ Millions, discounted at)

0%

5%

10%

15%

Proved developed producing

1,855

1,597

1,353

1,169

Proved developed non-producing

55

47

39

33

Proved undeveloped

1,118

700

449

290

Total Proved

3,028

2,344

1,841

1,492

Probable

1,990

1,171

755

526

Total Proved Plus Probable Reserves (before tax)

5,019

3,515

2,596

2,018

Contingent Resources

The following table provides a breakdown of the economic, unrisked best estimate contingent resources associated with a portion of Enerplus’ Fort Berthold and Marcellus assets as at December 31, 2020.  These contingent resources are economic using the average of the three independent petroleum consulting firms’ price forecasts (McDaniel, GLJ and Sproule) as of January 1, 2021, use established technologies and are all classified in the “development pending” maturity sub-class. However, there is uncertainty that it will be commercially viable to produce any portion of the resources.

The evaluation of contingent resources associated with Enerplus’ properties and leases at Fort Berthold were conducted by Enerplus and audited by McDaniel. NSAI evaluated 100% of Enerplus’ Marcellus shale gas assets in the U.S., including the estimate of contingent resources.

Please see Enerplus’ Annual Information Form (“AIF”) – Appendix A for additional disclosures related to Enerplus’ contingent resources as at December 31, 2020. The AIF is available at www.enerplus.com as well as on the Company’s SEDAR profile at www.sedar.com.

Development Pending Contingent Resources

Unrisked “Best Estimate”
Contingent Resources

Contingent Resources

Net Drilling Locations

Fort Berthold – Bakken/Three Forks Tight oil wells

72.0

MMBOE

136.3

Marcellus – Shale gas

621.2

Bcf

32.6

Total

175.5

MMBOE

168.9

Live Conference Call

Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today, February 19, 2021 at 9:00 a.m. MT (11:00 a.m. ET) to discuss these results. Details of the conference call are as follows:

Date:

Friday, February 19, 2021

Time: 

9:00 am MT/11:00 am ET

Dial-In: 

416-764-8688

1-888-390-0546 (toll free)

Conference ID: 87527222

Audiocast: https://produceredition.webcasts.com/starthere.jsp?ei=1418451&tp_key=a39387ec4a

To ensure timely participation in the conference call, callers are encouraged to dial in 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:

Dial-In:

416-764-8677 

1-888-390-0541 (toll free)

Passcode:

527222 #

Electronic copies of Enerplus’ 2020 MD&A and Financial Statements, along with other public information including investor presentations, are available on the Company’s website at www.enerplus.com.

Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.

INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL INFORMATION

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 and Reserves Information

All production volumes and revenues presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest with the exception of production utilized to calculate reserves replacement ratios which are on a working interest basis. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on “gross reserves” using forecast prices and costs. “Gross reserves” (as defined in NI 51-101), are Enerplus’ working interest before deduction of any royalties. Enerplus’ oil and gas reserves statement for the year ended December 31, 2020, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, is contained within our Annual Information Form (AIF) for the year ended December 31, 2020 which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on EDGAR concurrently with this news release for more complete disclosure on our operations.

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.

Contingent Resources Estimates

This news release contains estimates of “contingent resources”. “Contingent resources” are not, and should not be confused with, oil and gas reserves. “Contingent resources” are defined in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) as “those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a project in the early evaluation stage. All of our contingent resources estimates are economic using established technologies and based on the average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2021. Enerplus expects to develop these contingent resources in the coming years however it is too early in their development for all of these resources to be classified as reserves at this time. A portion of these contingent resources are part of continuous development by the Company and are categorized as contingent resources primarily due to development timelines that go beyond what is already assigned as undeveloped reserves. There is uncertainty that Enerplus will produce any portion of the volumes currently classified as “contingent resources”. “Development pending contingent resources” refer to a “contingent resources” project maturity sub-class for a particular project where resolution of the final conditions for development are being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe. The “contingent resources” estimates contained herein are presented as the “best estimate” of the quantity that will actually be recovered, effective as of December 31, 2020.  A “best estimate” of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

For additional information regarding the primary contingencies which currently prevent the classification of Enerplus’ disclosed “contingent resources” associated with Enerplus’ Marcellus shale gas properties and Fort Berthold properties as reserves and the positive and negative factors relevant to the “contingent resources” estimates, see Appendix A to Enerplus’ AIF, a copy of which is available under Enerplus’ SEDAR profile at www.sedar.com, and Enerplus’ Form 40-F, a copy of which is available under Enerplus’ EDGAR profile at www.sec.gov.

F&D and FD&A Costs

F&D costs presented in this news release are calculated (i) in the case of F&D costs for proved developed producing reserves, by dividing the sum of the exploration and development costs incurred in the year, by the additions to proved developed producing reserves in the year, (ii) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (iii) in the case of F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. F&D costs are presented in Canadian dollars per working interest BOE unless otherwise specified.

FD&A costs presented in this news release are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding, development and acquisition costs related to its reserves additions for that year. FD&A costs are presented in Canadian dollars per working interest BOE unless otherwise specified.

NOTICE TO U.S. READERS

The oil and natural gas reserves information contained in this news release has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as “proved reserves” and “probable reserves” may be defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the “SEC”) rules. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above with respect to production information, “company interest”) volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period.  Additionally, the SEC prohibits disclosure of oil and gas resources in SEC filings, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “Contingent Resources Estimates” above.

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: the continued uncertainty regarding timing and impact of the COVID-19 pandemic; anticipated completion, including timing, of the Bruin Acquisition and its expected impacted of on Enerplus’ operations and financial results; expected 2021 production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program, timing of related production, and ultimate well recoveries; oil and natural gas prices and differentials and our commodity risk management programs in 2021 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2021, net debt to adjusted funds-flow ratio, financial capacity and liquidity and capital resources to fund capital spending and working capital requirements; and our ESG initiatives, including GHG emissions and freshwater reduction targets.

The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: closing of the Bruin Acquisition substantially on the terms and timelines previously announced; that we will conduct our operations and achieve results of operations as anticipated; 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; estimated commodity price, differentials and cost assumptions, including continued operation of DAPL; the general continuance of current or, where applicable, assumed industry conditions; 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; the availability of third party services; the extent of our liabilities; 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, as well as closing of the Bruin Acquisition in early March 2021: a WTI price of 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 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 complete the Bruin Acquisition in accordance with its terms or at all and failure to realize the anticipated benefits of the Bruin Acquisition; unanticipated operating results, results from our capital spending activities or production declines; 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; 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.

SOURCE Enerplus Corporation



Share This:



More News Articles


New SHOWCASE Directory Companies

 

CWB Group
Petronim Projects
BOAX Resource Management
GDM Pipelines
Intelliview Technologies
Hive Innovations
Acero Engineering
Compass Bending