EX-99.3 4 erf-20221231xex99d3.htm EX-99.3

2022 FINANCIAL SUMMARY

Exhibit 99.3


	Three months ended				Twelve months ended
SELECTED FINANCIAL RESULTS	December 31,				December 31,
	2022		2021		2022		2021
Financial (US$, thousands, except ratios)
Net Income/(Loss)	$	330,708	$	176,913	$	914,302	$	234,441
Adjusted Net Income⁽¹⁾		181,069		129,958		707,061		315,669
Cash Flow from Operating Activities		316,584		283,534		1,173,382		604,839
Adjusted Funds Flow		315,379		258,477		1,230,289		712,433
Dividends to Shareholders - Declared		12,223		7,884		41,597		30,535
Net Debt		221,516		640,423		221,516		640,423
Capital Spending		85,647		81,059		432,004		302,348
Property and Land Acquisitions		2,853		2,744		22,515		835,147
Property and Land Divestments		211,987		108,869		231,373		112,651
Net Debt to Adjusted Funds Flow Ratio		0.2x		0.9x		0.2x		0.9x

Financial per Weighted Average Shares Outstanding
Net Income/(Loss) - Basic	$	1.49	$	0.71	$	3.91	$	0.93
Net Income/(Loss) - Diluted		1.43		0.68		3.77		0.90
Weighted Average Number of Shares Outstanding (000’s) - Basic		222,404		250,359		233,946		251,909
Weighted Average Number of Shares Outstanding (000’s) - Diluted		231,149		258,365		242,673		259,851

Selected Financial Results per BOE⁽²⁾⁽³⁾
Crude Oil & Natural Gas Sales⁽⁴⁾	$	55.78	$	52.82	$	64.27	$	44.04
Commodity Derivative Instruments		(4.83)		(7.12)		(9.48)		(4.84)
Operating Expenses		(9.68)		(8.46)		(9.99)		(8.69)
Transportation Costs		(4.04)		(4.27)		(4.22)		(3.81)
Production Taxes		(4.03)		(3.47)		(4.56)		(3.03)
General and Administrative Expenses		(1.15)		(1.12)		(1.17)		(1.14)
Cash Share-Based Compensation		(0.21)		(0.22)		(0.16)		(0.20)
Interest, Foreign Exchange and Other Expenses		0.56		(0.82)		(0.32)		(1.08)
Current Income Tax Recovery/(Expense)		(0.34)		(0.02)		(0.77)		(0.08)
Adjusted Funds Flow	$	32.06	$	27.32	$	33.60	$	21.17


	Three months ended				Twelve months ended
SELECTED OPERATING RESULTS	December 31,				December 31,
	2022		2021		2022		2021
Average Daily Production⁽³⁾
Crude Oil (bbls/day)		54,601		55,419		52,017		48,514
Natural Gas Liquids (bbls/day)		10,755		9,540		9,681		7,823
Natural Gas (Mcf/day)		249,351		227,186		231,770		215,304
Total (BOE/day)		106,915		102,823		100,326		92,221

% Crude Oil and Natural Gas Liquids		61%		63%		61%		61%

Average Selling Price⁽³⁾⁽⁴⁾
Crude Oil (per bbl)	$	83.06	$	75.21	$	93.63	$	65.89
Natural Gas Liquids (per bbl)		21.88		38.77		30.70		29.51
Natural Gas (per Mcf)		4.76		3.92		5.51		2.94

Net Wells Drilled		9.9		10.0		51.7		25.0

(1)	This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section in the following MD&A.

(2)	Non-cash amounts have been excluded.

(3)	Based on net production volumes. See “Basis of Presentation” section in the following MD&A.

(4)	Before transportation costs and commodity derivative instruments.

ENERPLUS 2022 FINANCIAL SUMMARY 1


	Three months ended				Twelve months ended
	December 31,				December 31,
Average Benchmark Pricing	2022		2021		2022		2021
WTI Crude Oil ($/bbl)	$	82.65	$	77.19	$	94.23	$	67.92
Brent (ICE) Crude Oil ($/bbl)		88.60		79.80		98.89		70.79
Propane – Conway ($/bbl)		34.21		52.42		46.03		43.74
NYMEX Natural Gas – Last Day ($/Mcf)		6.26		5.83		6.64		3.84
CDN/US Average Exchange Rate		0.74		0.79		0.77		0.80


Share Trading Summary	U.S.⁽¹⁾ – ERF		CDN⁽²⁾ – ERF
For the twelve months ended December 31, 2022	(US$)		(CDN$)
High	$	19.23	$	25.72
Low	$	10.21	$	12.96
Close	$	17.65	$	23.90

(1)	NYSE and other U.S. trading data combined.

(2)	TSX and other Canadian trading data combined.


2022 Dividends Declared per Share		US$		CDN$⁽¹⁾
First Quarter Total	$	0.033	$	0.042
Second Quarter Total	$	0.043	$	0.056
Third Quarter Total	$	0.050	$	0.066
Fourth Quarter Total	$	0.055	$	0.075
Total Year to Date	$	0.181	$	0.239

(1)	CDN$ dividends converted at the relevant foreign exchange rate closer to the payment date.

2 ENERPLUS 2022 FINANCIAL SUMMARY

2022 HIGHLIGHTS

FINANCIAL & OPERATIONAL HIGHLIGHTS

●

We delivered 2022 total production of 100,326 BOE/day, which was in line with our revised production guidance range (99,750 BOE/day to 101,000 BOE/day). Total production in 2022 was 9% higher compared to 2021. Crude oil and natural gas liquids production in 2022 was 61,698 bbls/day, which was in line with our revised guidance range (61,500 bbls/day to 62,500 bbls/day) and 10% higher compared to 2021. The higher year-over-year production was primarily due to a full period of production from the acquisitions in North Dakota completed during the first half of 2021, increased completions activity in North Dakota and the Marcellus, and strong well performance. These increases were partially offset by the impact of severe winter weather in North Dakota in April and December 2022, the Canadian asset divestments completed during the fourth quarter of 2022, and the Sleeping Giant and Russian Creek divestment completed during the fourth quarter of 2021.

●

Full year 2022 net income was $914.3 million, or $3.91 per share, compared to net income of $234.4 million, or $0.93 per share, in 2021. In 2022, adjusted net income¹ was $707.1 million, or $3.02 per share, compared to $315.7 million, or $1.25 per share, in 2021. The higher net income and adjusted net income was primarily due to higher commodity prices and production.

●

Our realized 2022 Bakken crude oil price differential was $1.09/bbl above WTI, compared to $2.15/bbl below WTI in 2021. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year.

●

Our 2022 Marcellus natural gas price differential was $0.72/Mcf below NYMEX, compared to $0.81/Mcf below NYMEX in 2021. The stronger pricing was driven by both inventory and supply concerns, particularly in Europe, given the reduction in natural gas supply from Russia for the upcoming winter, slightly offset by lower Northeast U.S. demand during the fall shoulder season.

●

Operating expenses in 2022 were $9.99/BOE, compared to $8.69/BOE in 2021. The increase in operating expenses in 2022 was primarily due to the impact of contracts with price escalators linked to WTI and the Consumer Price Index, as well as increased well service activity and costs. Cash general and administrative (“G&A”) expenses in 2022 were $1.17/BOE, compared to $1.14/BOE in 2021.

●

Capital spending totaled $432.0 million in 2022, in line with our guidance of $430 million.

●

During 2022, a total of $452.5 million was returned to shareholders through share repurchases and dividends. In 2022, we repurchased 27.9 million shares at an average price of $14.71 per share for a total cost of $410.9 million and paid $41.6 million in dividends.

●

We ended the year with net debt of $221.5 million, with $56.3 million drawn on our $900 million sustainability linked lending bank credit facility and were undrawn on our $365 million sustainability linked lending bank credit facility. At December 31, 2022, our net debt to adjusted funds flow ratio was 0.2x compared to 0.9x at December 31, 2021.

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

ENERPLUS 2022 FINANCIAL SUMMARY 3

YEAR END 2022 RESERVES SUMMARY

U.S. Standards¹ - after deduction of royalties (“net”), constant prices, U.S. dollars:

●

Net total proved reserves were 322.3 MMBOE, a decrease of 5% year-over-year, with the reduction driven by the sale of substantially all of our Canadian assets in 2022. Excluding reserves changes due to the Canadian asset sales, net total proved reserves increased 2% year-over-year

●

Enerplus added 40.8 MMBOE of net proved reserves in 2022 (including technical revisions and economic factors), replacing 112% of its 2022 net production

●

Net proved developed producing (“PDP”) finding and development (“F&D”) costs were $8.27 per BOE

●

Net proved F&D costs were $16.43 per BOE, including future development costs (“FDC”)

Canadian NI 51-101 Standards² - before deduction of royalties (“gross”), forecast prices, U.S. dollars:

●

Gross proved plus probable (“2P”) reserves were 601.1 MMBOE, a decrease of 2% year-over-year, with the reduction driven by the sale of substantially all of our Canadian assets in 2022. Excluding reserves changes due to the Canadian asset sales, gross 2P reserves increased 3% year-over-year

●

Enerplus added 63.3 MMBOE of gross 2P reserves in 2022 (including technical revisions and economic factors), replacing 139% of its 2022 gross production

●

Gross PDP F&D costs were $7.15 per BOE

●

Gross 2P F&D costs were $17.82 per BOE, including FDC

¹See “Presentation of Reserves Information” section in the following MD&A for definition of U.S. Standards.

²See “Basis of Presentation” section in the following MD&A for definition of Canadian NI 51-101 Standards.

4 ENERPLUS 2022 FINANCIAL SUMMARY

MD&A

Exhibit 99.3

Management’s Discussion and Analysis (“MD&A”)

The following discussion and analysis of financial results is dated February 23, 2023 and is to be read in conjunction with the audited consolidated financial statements (the “Financial Statements”) of Enerplus Corporation (“Enerplus” or the “Company”), as at December 31, 2022 and 2021 and for the years ended December 31, 2022, 2021 and 2020.

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 and Other Financial Measures” at the end of this MD&A for further information.

BASIS OF PRESENTATION

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

Subsequent to the year ended December 31, 2022, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiary.

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

In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in the Financial Statements. In addition, unless otherwise noted, all production volumes are presented on a “net” basis (after deduction of royalty obligations plus the Company’s royalty interests) consistent with U.S. oil and gas reporting standards. All reserves information in this MD&A has been prepared in accordance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“Canadian NI 51-101 Standards”). Reserves information in this MD&A is presented in accordance with Canadian NI 51-101 Standards and also in accordance with oil and gas disclosure framework of the United States Securities and Exchange Commission (the “SEC”). See “Presentation of Reserves Information” section in this MD&A.

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.

ENERPLUS 2022 FINANCIAL SUMMARY 5

2022 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 106,915 BOE/day, in line with our fourth quarter production guidance range of 105,000 BOE/day – 110,000 BOE/day and a decrease compared to production of 107,808 BOE/day in the third quarter of 2022. Crude oil and natural gas liquids production averaged 65,356 bbls/day compared to the third quarter average of 68,382 bbls/day, in line with our fourth quarter liquids production guidance range of 64,000 bbls/day – 68,000 bbls/day. The decrease in fourth quarter production was primarily due to the impact of severe winter weather in December and the Canadian asset divestments. Our fourth quarter capital spending was $85.6 million, bringing total 2022 capital spending to $432 million, in line with our revised guidance of $430 million.

On October 31, 2022, the Company completed a disposition of certain Canadian assets for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. Total consideration was comprised of cash, common shares of the purchaser, and an amortizing interest-bearing secured loan provided by Enerplus. After purchase price adjustments and transaction costs, adjusted proceeds were $80.8 million.

On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. Total consideration was comprised of cash and common shares of the purchaser. After purchase price adjustments and transaction costs, adjusted proceeds were $132.2 million.

We reported net income of $330.7 million in the fourth quarter compared to net income of $305.9 million in the third quarter of 2022. The increase in net income was primarily the result of a $151.9 million gain on the sale of Canadian assets, offset by lower production and realized prices.

Fourth quarter cash flow from operating activities and adjusted funds flow decreased to $316.6 million and $315.4 million respectively, from $409.9 million and $355.6 million, in the third quarter of 2022 due to lower production and realized prices, partially offset by a decrease in realized commodity derivative instrument losses.

Selected Fourth Quarter U.S and Canadian Financial Results


	Three months ended December 31, 2022							Three months ended December 31, 2021
($ millions, except per unit amounts)		U.S.		Canada		Total			U.S.		Canada		Total
Average Daily Production Volumes
Light and medium oil (bbls/day)			—		1,512		1,512		—		2,185		2,185
Heavy oil (bbls/day)			—		1,668		1,668		—		3,224		3,224
Tight oil (bbls/day)			51,421		—		51,421		50,010		—		50,010
Total crude oil (bbls/day)			51,421		3,180		54,601		50,010		5,409		55,419

Natural gas liquids (bbls/day)			10,679		76		10,755		9,236		304		9,540

Conventional natural gas (Mcf/day)			—		2,323		2,323		—		7,997		7,997
Shale gas (Mcf/day)			246,917		111		247,028		218,952		237		219,189
Total natural gas (Mcf/day)			246,917		2,434		249,351		218,952		8,234		227,186
Total average daily production (BOE/day)			103,253		3,662		106,915		95,738		7,085		102,823

Pricing⁽¹⁾
Crude oil (per bbl)		$	84.27	$	63.58	$	83.06	$	76.49	$	63.39	$	75.21
Natural gas liquids (per bbl)			21.73		43.56		21.88		38.56		45.06		38.77
Natural gas (per Mcf)			4.76		4.75		4.76		3.90		4.53		3.92

Property, Plant and Equipment
Capital and office expenditures		$	84.6	$	1.7	$	86.3	$	77.6	$	4.0	$	81.6
Property and land acquisitions			2.7		0.1		2.9		2.1		0.6		2.7
Property and land divestments			1.0		(213.0)		(212.0)		(108.0)		(0.9)		(108.9)

Netback Before Impact of Commodity Derivative Contracts⁽²⁾
Crude oil and natural gas sales		$	528.6	$	20.1	$	548.7	$	463.2	$	36.4	$	499.6
Operating expenses			(89.4)		(5.8)		(95.2)		(69.2)		(10.8)		(80.0)
Transportation costs			(38.6)		(1.1)		(39.7)		(39.1)		(1.3)		(40.4)
Production taxes			(39.1)		(0.5)		(39.6)		(32.3)		(0.5)		(32.8)
Netback before impact of commodity derivative contracts		$	361.5	$	12.7	$	374.2	$	322.6	$	23.8	$	346.4

(1)	Before transportation costs and the effects of commodity derivative instruments.

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

6 ENERPLUS 2022 FINANCIAL SUMMARY

Comparing the fourth quarter of 2022 with the same period in 2021:

●

Average daily production was 106,915 BOE/day, an increase of 4% from 102,823 BOE/day in the fourth quarter of 2021. The increase in crude oil and natural gas production was due to strong well performance and increased completions activity in North Dakota and the Marcellus during 2022, partially offset by the impact of severe winter weather in North Dakota in December, and the Canadian asset divestments completed during the fourth quarter of 2022.

●	Our crude oil and natural gas liquids production accounted for 61% of our total production mix in the fourth quarter of 2022, compared to 63% in 2021.

●	Capital spending increased to $85.6 million compared to $81.1 million in the fourth quarter of 2021, with the majority of the spending focused on our U.S. crude oil properties, including the drilling and completion of 10 net wells.

●	Operating expenses were $95.2 million or $9.68/BOE compared to $80.0 million or $8.46/BOE in the fourth quarter of 2021. The increase was primarily due to the impact of contracts with price escalators linked to WTI and the Consumer Price Index, as well as increased well service activity and costs.

●	Cash G&A expenses increased to $11.3 million, compared to $10.6 million in 2021, and increased on a per BOE basis to $1.15/BOE in the fourth quarter of 2022, compared to $1.12/BOE in the same period of 2021, due to inflationary pressure on labour and services.

●

During the fourth quarter of 2022, our Bakken crude oil price differential averaged $1.05/bbl above WTI, compared to $0.88/bbl below WTI for the same period in 2021. Bakken crude oil price differentials continued to trade above WTI due to excess pipeline capacity in the region, as well as continued demand for crude oil delivered to the U.S. Gulf Coast region.

●	Our fourth quarter 2022 Marcellus natural gas differential was $1.18/Mcf below NYMEX, compared to $1.70/Mcf below NYMEX during the same period in 2021. Our Marcellus differential narrowed due to stronger regional prices as we entered the winter season.

●

We reported net income of $330.7 million in the fourth quarter of 2022 compared to $176.9 million in the fourth quarter of 2021. Net income increased due to a $151.9 million gain on the sale of the remaining Canadian assets as well as increased production in the Bakken and Marcellus, and stronger commodity prices.

●

Cash flow from operating activities and adjusted funds flow increased to $316.6 million and $315.4 million, respectively, in the fourth quarter of 2022, compared to $283.5 million and $258.5 million in the fourth quarter of 2021. This was due to increased production in the Bakken and Marcellus and higher realized prices.

●

During the fourth quarter of 2022, we repurchased and cancelled 9,798,752 common shares under a normal course issuer bid (“NCIB”) at an average price of $17.24 per common share. During the fourth quarter of 2021, we repurchased and cancelled 11,240,071 common shares under the NCIB at an average price of $10.08 per common share.

●	During the fourth quarter of 2022, the Board of Directors approved a 10% increase to the quarterly dividend to $0.055 per share, from $0.050 per share.

●	Net debt to adjusted funds flow was 0.2x at December 31, 2022 compared to 0.9x at December 31, 2021.

ENERPLUS 2022 FINANCIAL SUMMARY 7

2022 OVERVIEW AND 2023 OUTLOOK


Summary of Guidance and Results	Revised 2022 Guidance	2022 Results	2023 Guidance
Capital spending ($ millions)	$430	$432	$500 - $550
Average annual production (BOE/day)	99,750 - 101,000	100,326	93,000 - 98,000
Average annual crude oil and natural gas liquids production (bbls/day)	61,500 - 62,500	61,698	57,000 - 61,000
Fourth quarter average production (BOE/day)	105,000 - 110,000	106,915	—
Fourth quarter average crude oil and natural gas liquids production (bbls/day)	64,000 - 68,000	65,356	—
Average production tax rate (% of gross sales, before transportation)	7%	7%	7%
Operating expenses (per BOE)	$10.00	$9.99	$10.75 - $11.75
Transportation costs (per BOE)	$4.25	$4.22	$4.35
Cash G&A expenses (per BOE)	$1.20	$1.17	$1.35
Current tax expense (% of adjusted funds flow before tax)	2% - 3%	2%	5% - 6%

Differential/Basis Outlook and Results⁽¹⁾
Average U.S. Bakken crude oil differential (compared to WTI crude oil)	$1.25/bbl	$1.09/bbl	$0.75/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)	$(0.75)/Mcf	$(0.72)/Mcf	($0.75)/Mcf

(1)	Excludes transportation costs.

2022 OVERVIEW

Our 2022 annual average production was 100,326 BOE/day with crude oil and natural gas liquids volumes of 61,698 bbls/day, consistent with our revised production guidance target of 99,750 BOE/day – 101,000 BOE/day and revised crude oil and natural gas liquids production guidance of 61,500 bbls/day – 62,500 bbls/day. Our capital spending for the year totaled $432 million, in line with our revised guidance of $430 million. The majority of our capital was directed to our U.S. crude oil properties, with approximately 86% of total spending focused on our North Dakota properties. The success of our capital program delivered crude oil and natural gas liquids production growth of 10% and overall production growth of 9% compared to 2021.

During 2022, a total of $452.5 million, representing 57% of free cash flow¹, was returned to shareholders through share repurchases and dividends compared to $153.7 million in 2021. In 2022, we repurchased 11% of our outstanding common shares at an average price of $14.71 per common share. During 2022, we increased our quarterly dividend three times resulting in a 67% increase to $0.055 per common share, and paid a total of $41.6 million (December 31, 2021 - $30.5 million).

Our Bakken sales price differentials averaged $1.09/bbl above WTI, below our revised guidance of $1.25/bbl above WTI. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year. Our Marcellus differential of $0.72/Mcf below NYMEX was in line with our differential guidance of $0.75/Mcf below NYMEX.

Operating expenses were $9.99/BOE, in line with our revised guidance of $10.00/BOE and representing a 15% increase from the prior year. The increase was due to contracts with price escalators linked to WTI crude oil prices and the Consumer Price Index, as well as increased well service activity and costs. Cash G&A expenses were $1.17/BOE, lower than our revised guidance of $1.20/BOE.

Cash flow from operations and adjusted funds flow increased to $1,173.4 million and $1,230.3 million, respectively, from $604.8 million and $712.4 million in 2021. The increase was due to an increase in crude oil and natural gas sales as a result of our capital program and increased commodity prices.

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

8 ENERPLUS 2022 FINANCIAL SUMMARY

We reported net income of $914.3 million in 2022, compared to net income of $234.4 million in 2021. The increase in net income was due to an increase in production, stronger commodity prices, a decrease in commodity derivative instrument losses, and a $151.9 million gain on the sale of Canadian assets, partially offset by higher income tax expense in 2022.

At December 31, 2022, net debt was $221.5 million and our net debt to adjusted funds flow ratio decreased to 0.2x in 2022 from 0.9x in 2021. During the fourth quarter of 2022, Enerplus converted its $400 million revolving bank credit facility to a $365 million sustainability linked lending (“SLL”) bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility (together referred to as the “Bank Credit Facilities”), which was renewed with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the two agreements’ terms or covenants.

2023 OUTLOOK

In 2023, we plan to continue to focus on creating value for shareholders through sustainable crude oil and natural gas liquids production growth. The 2023 capital budget is expected to deliver robust free cash flow. We expect our capital spending for 2023 to range between $500 - $550 million, with the majority directed to our North Dakota assets.

Annual average production is expected to be 93,000 BOE/day - 98,000 BOE/day, including 57,000 bbls/day - 61,000 bbls/day of crude oil and natural gas liquids production.

We expect our Bakken sales price differential to average $0.75/bbl above WTI in 2023. In the Marcellus, we have a differential outlook of $0.75/Mcf below NYMEX in 2023.

We expect operating expenses to average between $10.75/BOE - $11.75/BOE and cash G&A expenses to average $1.35/BOE during 2023. We also expect 2023 cash tax of approximately 5 - 6% of adjusted funds flow before tax assuming WTI of $80.00/bbl and NYMEX of $3.50/Mcf.

We plan to continue to return at least 60% of free cash flow¹ to our shareholders in 2023 through share repurchases and dividends, based on current market conditions. Remaining free cash flow not allocated to return of capital is expected to be directed to reinforcing the balance sheet. We intend to renew the NCIB in August 2023. Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share to be paid in March 2023. We expect to fund the dividend through the free cash flow generated by the business.

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

ENERPLUS 2022 FINANCIAL SUMMARY 9

RESULTS OF OPERATIONS

Production


Average Daily Production Volumes	2022	2021	2020
Light and medium oil (bbls/day)	1,950	2,231	2,601
Heavy oil (bbls/day)	2,556	3,302	3,424
Tight oil (bbls/day)	47,511	42,981	30,656
Total crude oil (bbls/day)	52,017	48,514	36,681

Natural gas liquids (bbls/day)	9,681	7,823	4,499

Conventional natural gas (Mcf/day)	5,925	7,818	11,416
Shale gas (Mcf/day)	225,845	207,486	179,598
Total natural gas (Mcf/day)	231,770	215,304	191,014
Total daily sales (BOE/day)	100,326	92,221	73,016

Production in 2022 averaged 100,326 BOE/day, in line with our revised production guidance range of 99,750 BOE/day - 101,000 BOE/day, and resulted in a 9% increase compared to 2021 production of 92,221 BOE/day. Crude oil and natural gas liquids production in 2022 averaged 61,698 bbls/day, in line with our revised guidance range of 61,500 bbls/day - 62,500 bbls/day. Compared to 2021, our crude oil and natural gas liquids production increased 10% due to the impact of 44 net wells coming onstream in North Dakota during 2022. Additionally, there was a full year of production from the acquisition of Bruin E&P Holdco, LLC (the “Bruin Acquisition”) and certain assets in the Williston Basin from Hess Bakken Investment II, LLC (the “Dunn County Acquisition”), which were acquired in the first half of 2021. These increases were partially offset by the impact of severe winter weather in North Dakota in April and December 2022, the sale of our interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, which closed during the fourth quarter of 2021, and the sale of substantially all of our Canadian assets in the fourth quarter of 2022.

Our U.S. production volumes increased by 11% compared to 2021 and our U.S. crude oil and natural gas liquids production increased by 13% to 56,950 bbls/day, due to higher completions activity, and a full year of production from the Bruin and Dunn County assets in 2022, compared to 2021. Natural gas production in the Marcellus increased by 7% to 28,158 BOE/day in 2022, compared to 26,324 BOE/day in 2021, due to new wells coming on-stream in 2022.

Canadian production volumes decreased by 20% compared to the prior year, due to the closing of the sale of substantially all of our remaining Canadian assets to two separate purchasers during the fourth quarter of 2022. Combined production from the two divestments was 6,400 BOE/day. We expect no Canadian production in 2023.

Our crude oil and natural gas liquids production accounted for 61% of our total average daily production in 2022, consistent with 61% in 2021.

Production for 2021 increased by 26%, compared to 2020, largely due to production from the Bruin and Dunn County assets acquired in the first half of 2021 and the impact of 43 net wells coming onstream in North Dakota during 2021. Production in 2020 was impacted by temporary curtailments and the suspension of all operated drilling and completion activity in North Dakota during the second quarter of 2020, in response to the significant decline in crude oil prices as a result of the COVID-19 pandemic.

2023 Guidance

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

10 ENERPLUS 2022 FINANCIAL SUMMARY

Pricing

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:


Pricing (average for the period)	2022		2021		2020
Benchmarks
WTI crude oil ($/bbl)	$	94.23	$	67.92	$	39.40
Brent (ICE) crude oil ($/bbl)		98.89		70.79		43.21
Propane – Conway ($/bbl)		46.03		43.74		18.59
NYMEX natural gas – last day ($/Mcf)		6.64		3.84		2.08
CDN/US average exchange rate		0.77		0.80		0.75
CDN/US period end exchange rate		0.74		0.79		0.79

Enerplus selling price⁽¹⁾
Crude oil ($/bbl)	$	93.63	$	65.89	$	33.30
Natural gas liquids ($/bbl)		30.70		29.51		7.79
Natural gas ($/Mcf)		5.51		2.94		1.40

Average benchmark differentials
Bakken DAPL - WTI ($/bbl)	$	2.62	$	(0.79)	$	(4.27)
Brent (ICE) - WTI ($/bbl)		4.66		2.87		3.81
MSW Edmonton – WTI ($/bbl)		(1.81)		(3.88)		(5.33)
WCS Hardisty – WTI ($/bbl)		(18.28)		(13.04)		(12.60)
Transco Leidy monthly – NYMEX ($/Mcf)		(1.04)		(0.94)		(0.72)
Transco Z6 Non-New York monthly – NYMEX ($/Mcf)		(0.12)		(0.36)		(0.34)

Enerplus realized differentials⁽¹⁾⁽²⁾
Bakken crude oil – WTI ($/bbl)	$	1.09	$	(2.15)	$	(5.39)
Marcellus natural gas – NYMEX ($/Mcf)		(0.72)		(0.81)		(0.65)
Canada crude oil – WTI ($/bbl)		(15.80)		(12.94)		(13.22)

(1)	Excluding transportation costs and the effects of commodity derivative instruments.

(2)	Based on a weighted average differential for the period.

CRUDE OIL AND NATURAL GAS LIQUIDS

Benchmark WTI prices averaged $94.23/bbl in 2022, a 39% increase from 2021. The Russian invasion of Ukraine and the consequential impact on global oil supply resulted in crude oil prices trading above $120/bbl during the second quarter of 2022. Prices moderated during the second half of 2022 driven mainly by concerns over a global recession as central banks aggressively raised key interest rates in response to year-over-year inflation. North American oil supply growth remained moderate as the industry continued its capital discipline while focusing on shareholder returns. In addition, global inventory balances remain tight, supported by the policy of the Organization of the Petroleum Exporting Countries Plus (“OPEC+”) to maintain certain levels of production curtailments to provide support and stability to global oil markets.

Our 2022 realized crude oil price averaged $93.63/bbl, representing a 42% increase compared to 2021, which reflects the improvement in WTI pricing as well as stronger sales price differentials for our Bakken crude oil production.

Our Bakken sales price differentials improved by $3.24/bbl in 2022 compared to 2021, averaging $1.09/bbl above WTI. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year. The outlook for Bakken production growth continues to be relatively modest and as such we expect differentials to remain supportive given the excess pipeline capacity out of the basin. For 2023 we expect our realized Bakken differential to average $0.75/bbl above WTI.

Canadian crude oil differentials weakened in 2022 compared to the prior year, particularly in the second half of 2022. Heavy differentials traded at wider discounts due in part to production growth, with Canadian production reaching records levels in the fourth quarter of 2022. An unplanned outage on TC Energy’s Keystone Pipeline system and increasing apportionment levels on the Enbridge Mainline added further pressure on Canadian crude oil differentials.

ENERPLUS 2022 FINANCIAL SUMMARY 11

We realized an average price of $30.70/bbl on our natural gas liquids production in 2022, a 4% increase compared to 2021. North American natural gas liquids pricing increased in the first quarter of 2022 in part due to the strength in overall commodity prices caused by the Russian invasion of Ukraine. Natural gas liquids benchmark prices declined during the second half of the year due to growing concerns around global recession risk, industrial demand for petrochemical feedstocks and inventory accumulations.

Monthly Crude Oil Prices

NATURAL GAS

Our realized natural gas price averaged $5.51/Mcf in 2022, an 87% increase from 2021. Our realized price increased more than the NYMEX natural gas benchmark price due to strength in regional natural gas prices in the Northeast U.S.

In the Marcellus, we realized an average sales price differential of $0.72/Mcf below NYMEX which was narrower than our 2021 realized sales price differential of $0.81/Mcf. NYMEX natural gas prices at Henry Hub settled higher during this period due to both inventory and supply concerns, particularly in Europe, given the reduction in natural gas supply from Russia for the upcoming winter. Transco Z6 Non-New York monthly benchmark differentials averaged $0.12/Mcf below NYMEX for 2022, $0.24/Mcf narrower versus 2021. The Transco Leidy monthly benchmark differential averaged $1.04/Mcf below NYMEX for 2022, which was wider than 2021 due to lower Northeast U.S. demand during the fall shoulder season. For 2023, we expect our Marcellus differential to average $0.75/Mcf below NYMEX.

12 ENERPLUS 2022 FINANCIAL SUMMARY

Monthly Natural Gas Prices

FOREIGN EXCHANGE

Fluctuations in the CDN/US dollar exchange rate impacts the amount of our Canadian dollar denominated costs such as G&A expenses and dividends paid to Canadian residents. The U.S. dollar strengthened compared to the Canadian dollar during 2022 as a result of the Russian invasion of Ukraine and concerns over a global recession. The exchange rate averaged $0.77 CDN/US in 2022, compared to $0.80 CDN/US during 2021, and ended the year at $0.74 CDN/US in 2022.

Monthly CDN/US Exchange Rate

Price Risk Management

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

We expect our commodity derivative contracts to protect a portion of our cash flow from operating activities and adjusted funds flow. As of February 22, 2023, we have 15,000 bbls/day hedged for first half of 2023 and 5,000 bbls/day hedged for the second half of 2023. We have also hedged 120,000 Mcf/day for the period from January 1, 2023 to March 31, 2023 and 50,000 Mcf/day for the period from April 1, 2023 to October 31, 2023. Our crude oil contracts consist mainly of 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.

ENERPLUS 2022 FINANCIAL SUMMARY 13

The following is a summary of Enerplus’ financial contracts in place at February 22, 2023:



	WTI Crude Oil ($/bbl)⁽¹⁾⁽²⁾		NYMEX Natural Gas ($/Mcf)⁽²⁾
	Jan 1, 2023 –	Jul 1, 2023 –	Jan 1, 2023 –	Apr 1, 2023 –
	Jun 30, 2023	Dec 31, 2023	Mar 31, 2023	Oct 31, 2023
Swaps
Volume (bbls/day)	10,000	10,000	–	–
Brent - WTI Spread	$ 5.47	$ 5.47	–	–

3 Way Collars
Volume (bbls/day)	15,000	5,000	–	–
Sold Puts	$ 61.67	$ 65.00	–	–
Purchased Puts	$ 79.33	$ 85.00	–	–
Sold Calls	$ 114.31	$ 128.16	–	–

Collars
Volume (Mcf/day)	–	–	120,000	50,000
Volume (bbls/day)⁽³⁾	2,000	2,000	–	–
Purchased Puts	$ 5.00	$ 5.00	$ 6.27	$ 4.05
Sold Calls	$ 75.00	$ 75.00	$ 18.17	$ 7.00

(1)	The total average deferred premium spent on our outstanding crude oil contracts is $1.25/bbl from January 1, 2023 – December 31, 2023.

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

(3)	Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition.

ACCOUNTING FOR PRICE RISK MANAGEMENT


Commodity Risk Management Gains/(Losses)
($ millions)	2022		2021		2020
Realized gains/(losses):
Crude oil	$	(275.7)	$	(146.3)	$	92.8
Natural gas		(71.5)		(16.7)		—
Total realized gains/(losses)	$	(347.2)	$	(163.0)	$	92.8

Unrealized gains/(losses):
Crude oil	$	125.8	$	(111.6)	$	(19.9)
Natural gas		23.7		0.2		2.8
Total unrealized gains/(losses)	$	149.5	$	(111.4)	$	(17.1)
Total commodity derivative instruments gains/(losses)	$	(197.7)	$	(274.4)	$	75.7


(Per BOE)	2022		2021		2020
Total realized gains/(losses)	$	(9.48)	$	(4.84)	$	3.47
Total unrealized gains/(losses)		4.08		(3.31)		(0.64)
Total commodity derivative instruments gains/(losses)	$	(5.40)	$	(8.15)	$	2.83

During 2022, Enerplus realized losses of $275.7 million on crude oil contracts and $71.5 million on our natural gas contracts, compared to realized losses of $146.3 million on crude oil contracts and $16.7 million on our natural gas contracts in 2021. Realized losses in 2022 on crude oil and natural gas contracts were due to commodity prices exceeding the swap and sold call values on our commodity derivative contracts.

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 an unrealized loss or gain to earnings. At December 31, 2022, the fair value of our crude oil contracts was in a net liability position of $0.6 million (December 31, 2021 – net liability position of $146.7 million). The fair value of our natural gas contracts at December 31, 2022 was in a net asset position of $26.7 million (December 31, 2021 – net asset position of $3.0 million). The change in fair value of our crude oil and natural gas contracts represented unrealized gains of $125.8 million and unrealized gains of $23.7 million, respectively, during 2022 and unrealized losses of $111.6 million and unrealized gains of $0.2 million, respectively, during 2021.

14 ENERPLUS 2022 FINANCIAL SUMMARY

Crude oil and natural gas sales


($ millions)	2022		2021		2020
Crude oil and natural gas sales	$	2,353.4	$	1,482.6	$	553.7
Per BOE	$	64.27	$	44.04	$	20.72

Crude oil and natural gas sales for 2022 totaled $2,353.4 million, or $64.27/BOE, an increase of 59% from $1,482.6 million, or $44.04/BOE in 2021. The increase in revenue is a result of increased production volumes from our capital program and higher commodity prices. Refer to the “Pricing” section for further details in this MD&A.

Comparing 2021 to 2020, crude oil and natural gas sales increased 168% to $1,482.6 million, or $44.04/BOE, from $553.7 million, or $20.72/BOE, as a result of increased production volumes, including the combined impact of the Bruin and Dunn County acquisitions in 2021, as well as higher commodity prices.

Operating Expenses


($ millions, except per BOE amounts)	2022		2021		2020
Operating expenses	$	365.7	$	292.4	$	197.1
Per BOE	$	9.99	$	8.69	$	7.38

Operating expenses for 2022 were $365.7 million or $9.99/BOE, in line with our revised guidance of $10.00/BOE and an increase of $73.3 million or $1.30/BOE from 2021. The increase was primarily due to the impact of contracts with price escalators linked to WTI crude oil prices and the Consumer Price Index, as well as increased well service activity and costs.

Operating expenses for 2021 were $292.4 million or $8.69/BOE, representing an increase of $95.3 million or $1.31/BOE from 2020. The increase was primarily due to higher U.S. crude oil production as a result of the Bruin and Dunn County acquisitions and increased liquids weighting. In addition, operating expenses increased due to higher well service activity in the second half of 2021 and higher water handling charges as a result of contracts with price escalators linked to WTI crude oil prices, which were triggered in 2021.

2023 Guidance

We expect operating expenses of between $10.75/BOE - $11.75/BOE for 2023, an increase from 2022 due to inflation adjusted contract prices and general cost escalation, increased gas processing due to improved gas capture rates, and higher well service activity.

Transportation Costs


($ millions, except per BOE amounts)	2022		2021		2020
Transportation costs	$	154.7	$	128.3	$	98.7
Per BOE	$	4.22	$	3.81	$	3.69

Transportation costs in 2022 were lower than our revised guidance of $4.25/BOE, averaging $4.22/BOE or $154.7 million, compared to $3.81/BOE or $128.3 million in 2021. The increase in transportation costs was primarily a result of increased U.S. production with higher associated transportation costs and additional firm transportation commitments on the Dakota Access Pipeline (“DAPL”) as a result of the Bruin Acquisition and participation in the DAPL expansion in August 2021.

Transportation costs in 2021 increased to $3.81/BOE compared to $3.69/BOE in 2020. The increase in transportation costs was primarily a result of increased U.S. production with higher associated transportation costs and additional firm transportation commitments compared to the prior year.

2023 Guidance

We expect an increase in transportation expenses to $4.35/BOE for 2023 due to the impact of contracts with price escalators linked to the Consumer Price Index and an expected increase in U.S. production.

ENERPLUS 2022 FINANCIAL SUMMARY 15

Production Taxes


($ millions, except per BOE amounts)	2022		2021		2020
Production taxes	$	167.0	$	102.0	$	37.4
Per BOE	$	4.56	$	3.03	$	1.40
Production taxes (% of crude oil and natural gas sales)		7.1%		6.9%		6.8%

Production taxes include state production taxes, Pennsylvania impact fees and Canadian freehold mineral taxes.

Production taxes were in line with our revised guidance of 7.0% for 2022, averaging 7.1% of crude oil and natural gas sales, before transportation. Production taxes of $167.0 million in 2022 increased in comparison to prior years due to higher realized commodity prices and production volumes. Production taxes of $102.0 million in 2021 were higher in comparison to 2020, due to higher realized commodity prices and production volumes.

2023 Guidance

We expect annual production taxes to average 7% in 2023.

Netbacks

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


	Year ended December 31, 2022
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			71,271 BOE/day		174,330 Mcfe/day		100,326 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	75.98	$	5.92	$	64.27
Operating expenses			(13.57)		(0.20)		(9.99)
Transportation costs			(3.76)		(0.89)		(4.22)
Production taxes			(6.30)		(0.05)		(4.56)
Netback before impact of commodity derivative contracts		$	52.35	$	4.78	$	45.50
Realized hedging gains/(losses)			(10.60)		(1.12)		(9.48)
Netback after impact of commodity derivative contracts		$	41.75	$	3.66	$	36.02
Netback before impact of commodity derivative contracts⁽¹⁾ ($ millions)		$	1,361.8	$	304.2	$	1,666.0
Netback after impact of commodity derivative contracts⁽¹⁾($ millions)		$	1,086.1	$	232.9	$	1,318.8

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

16 ENERPLUS 2022 FINANCIAL SUMMARY


	Year ended December 31, 2021
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			64,479 BOE/day		166,454 Mcfe/day		92,221 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	54.91	$	3.13	$	44.04
Operating expenses			(11.89)		(0.21)		(8.69)
Transportation costs			(3.11)		(0.91)		(3.81)
Production taxes			(4.23)		(0.04)		(3.03)
Netback before impact of commodity derivative contracts		$	35.68	$	1.97	$	28.51
Realized hedging gains/(losses)			(6.22)		(0.28)		(4.84)
Netback after impact of commodity derivative contracts		$	29.46	$	1.69	$	23.67
Netback before impact of commodity derivative contracts⁽¹⁾ ($ millions)		$	840.0	$	119.9	$	959.9
Netback after impact of commodity derivative contracts⁽¹⁾($ millions)		$	693.7	$	103.2	$	796.9

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


	Year ended December 31, 2020
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			45,277 BOE/day		166,434 Mcfe/day		73,016 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	27.81	$	1.52	$	20.72
Operating expenses			(10.91)		(0.27)		(7.38)
Transportation costs			(2.67)		(0.89)		(3.69)
Production taxes			(2.18)		(0.02)		(1.40)
Netback before impact of commodity derivative contracts		$	12.05	$	0.34	$	8.25
Realized hedging gains/(losses)			5.60		—		3.47
Netback after impact of commodity derivative contracts		$	17.65	$	0.34	$	11.72
Netback before impact of commodity derivative contracts⁽¹⁾ ($ millions)		$	199.7	$	20.8	$	220.5
Netback after impact of commodity derivative contracts⁽¹⁾($ millions)		$	292.6	$	20.8	$	313.4

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

As a result of the strong commodity price environment for both crude oil and natural gas, our netback before the impact of commodity derivative contracts¹ increased by 74% in 2022 compared to 2021, and our netback after the impact of commodity derivative contracts¹ increased by 65%. During 2022, our crude oil properties accounted for 82% of our netback before impact of commodity derivative contracts¹ and 82% of our netback after the impact of commodity derivative contracts¹, compared to 88% and 87%, respectively, in 2021.

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

ENERPLUS 2022 FINANCIAL SUMMARY 17

General and Administrative (“G&A”) Expenses

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


($ millions)	2022		2021		2020
Cash:
G&A expense	$	42.8	$	38.4	$	33.5
Share-based compensation expense		5.7		6.9		(0.9)

Non-Cash:
Share-based compensation expense		22.9		13.8		9.7
Equity swap loss/(gain)		(1.0)		(1.9)		1.0
G&A expense/(recovery)		(0.4)		(0.4)		(0.2)
Total G&A expenses	$	70.0	$	56.8	$	43.1


(Per BOE)	2022		2021		2020
Cash:
G&A expense	$	1.17	$	1.14	$	1.26
Share-based compensation expense		0.16		0.20		(0.04)

Non-Cash:
Share-based compensation expense		0.63		0.41		0.36
Equity swap loss/(gain)		(0.03)		(0.06)		0.04
G&A expense/(recovery)		(0.01)		(0.01)		(0.01)
Total G&A expenses	$	1.92	$	1.68	$	1.61

Cash G&A expenses were $42.8 million or $1.17/BOE in 2022, lower than our revised guidance of $1.20/BOE. Total cash G&A expenses increased due to inflationary pressure on labour and services, compared to 2021. Total cash G&A expenses were lower during 2020 due to a combination of salary reductions as well as COVID-19 pandemic government funding.

SBC can be equity settled or cash-settled, depending on the underlying plan to which it relates. Cash-settled SBC expense was $5.7 million or $0.16/BOE in 2022, compared to $6.9 million or $0.20/BOE in 2021, and relates to our director plans. The lower expense was due to fewer cash-settled units outstanding in 2022 compared to 2021, partially offset by an increase in share price. During 2020, we reported a cash SBC recovery due to a decrease in our share price during the year.

Equity settled non-cash SBC was $22.9 million or $0.63/BOE in 2022, compared to $13.8 million or $0.41/BOE in 2021 and $9.7 million or $0.36/BOE in 2020. Performance Share Units (“PSUs”), as one of the equity settled LTI plans, is impacted by performance multipliers. During 2022, the multipliers were higher than in 2021 resulting in increased expense. The equity settled non-cash SBC was lower in 2020, due to lower multipliers.

Enerplus previously had hedged a portion of the outstanding cash-settled units under our LTI plans. During 2022, we recorded an unrealized mark-to-market gain of $1.0 million on these equity derivative contracts as a result of the improved share price (2021 – $1.9 million gain). Enerplus settled its equity derivative contracts during 2022 and did not have any equity derivatives outstanding at December 31, 2022

2023 Guidance

We expect cash G&A expenses of $1.35/BOE for 2023.

18 ENERPLUS 2022 FINANCIAL SUMMARY

Interest Expense

Interest on our senior notes and Bank Credit Facilities for 2022 totaled $24.6 million, a decrease of 10% from $27.4 million in 2021. The decrease was primarily due to lower debt levels in 2022, compared to 2021, as a result of funding the 2021 Bruin and Dunn County acquisitions, offset by the impact of rising interest rates on our Bank Credit Facilities drawings in 2022. During 2022, we made our third principal payment out of five, and a bullet payment on our 2012 senior notes.

In 2021, interest on our senior notes and Bank Credit Facilities of $27.4 million increased compared to $20.7 million in 2020 due to higher debt levels as a result of the Bruin and Dunn County acquisitions, partially offset by the final repayment of our 2009 senior notes and scheduled repayment of our 2012 senior notes, which carried higher interest rates than our Bank Credit Facilities.

At December 31, 2022, approximately 78% of our debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43%, 57%), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2%, 1.9%).

Foreign Exchange


($ millions)	2022		2021		2020
Realized:
Foreign exchange (gain)/loss	$	(0.1)	$	3.5	$	0.8
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company		(0.9)		(2.3)		(0.9)
Unrealized:
Foreign exchange (gain)/loss on U.S. dollar working capital in parent company		11.2		(8.1)		1.3
Total foreign exchange (gain)/loss	$	10.2	$	(6.9)	$	1.2
CDN/US average exchange rate	$	0.77	$	0.80	$	0.75
CDN/US period end exchange rate	$	0.74	$	0.79	$	0.79

Enerplus recorded a total foreign exchange loss of $10.2 million in 2022, compared to a gain of $6.9 million in 2021 and a loss of $1.2 million in 2020. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies and the translation of our U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated working capital held in Canada at each period-end.

At December 31, 2022, $203.2 million of outstanding senior notes and $56.3 million drawn on the Bank Credit Facilities were designated as net investment hedges against the investment in our U.S. subsidiary. As a result, unrealized foreign exchange gains and losses on the translation of this U.S. dollar denominated debt are included in Other Comprehensive Income/(Loss). For the year ended December 31, 2022, Other Comprehensive Income/(Loss) included an unrealized loss of $26.5 million on our U.S. dollar denominated senior notes and Bank Credit Facilities (2021 – $4.1 million gain; 2020 – $1.8 million gain).

Property, Plant and Equipment


($ millions)	2022		2021		2020
Capital spending⁽¹⁾	$	432.0	$	302.3	$	217.2
Office capital		1.3		1.6		2.2
Sub-total		433.3		303.9		219.4
Bruin Acquisition	$	—	$	520.2	$	—
Dunn County Acquisition		—		305.1		—
Canadian divestments⁽¹⁾		(213.0)		—		—
Property and land acquisitions		22.5		9.8		7.5
Property and land divestments⁽¹⁾		(18.4)		(112.7)		(4.5)
Sub-total		(208.9)		722.4		3.0
Total	$	224.4	$	1,026.3	$	222.4

(1)	Excludes changes in non-cash investing working capital.

2022

Capital spending in 2022 totaled $432.0 million, in line with our revised guidance of $430 million. In 2022, we spent $368.0 million on our U.S. crude oil properties, and $57.6 million on our Marcellus natural gas assets. The increase in capital spending in 2022, compared to 2021, was due to increased capital activity on our North Dakota properties which includes properties from the 2021 Bruin and Dunn County acquisitions. Through our capital program, we added 63.3 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves in 2022, replacing 139% of our production, including economic factors and technical revisions and before accounting for acquisitions and divestments.

ENERPLUS 2022 FINANCIAL SUMMARY 19

On October 31, 2022, the Company completed a disposition of certain Canadian assets for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. After purchase price adjustments, proceeds from the two divestments were $213.0 million with $61.7 million allocated to PP&E, excluding the reduced asset retirement obligation.

Property and land acquisitions in 2022 totaled $22.5 million, which included minor acquisitions of leases and undeveloped land. We recorded other property and land divestments of $18.4 million in 2022.

2021

Capital spending in 2021 totaled $302.3 million, including $256.1 million on our U.S. crude oil properties, $13.8 million on our Canadian crude oil properties and $31.0 million on our Marcellus natural gas assets. Through our capital program in 2021, we added 85.0 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves, replacing 204% of our production, including economic factors and technical revisions and before accounting for acquisitions and divestments. Including acquired and divested volumes, we replaced 558% of our 2021 production adding 233.0 MMBOE of gross proved plus probable reserves.

During 2021, we completed the Bruin Acquisition for total cash consideration of $465.0 million or $420.2 million after purchase price adjustments, with $520.2 million allocated to PP&E, excluding the assumed asset retirement obligation. We also completed the Dunn County Acquisition for total cash consideration of $306.8 million, with $305.1 million allocated to PP&E, excluding the assumed asset retirement obligation.

Property divestments were related to the sale of our interest in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, during the fourth quarter of 2021 for total cash consideration of $115.0 million, before purchase price adjustments. After purchase price adjustments and transaction costs, adjusted proceeds of $107.8 million, were all allocated to PP&E, excluding the divested asset retirement obligation. Enerplus may receive up to $5.0 million in additional contingent payments if the WTI oil price averages over $65/bbl in 2022 and over $60/bbl in 2023. Subsequent to December 31, 2022, the Company received a $2.5 million contingent payment as a result of the WTI oil price exceeding $65/bbl in 2022.

2020

Capital spending in 2020 totaled $217.2 million, including $174.8 million on our U.S. crude oil properties, $17.4 million on our Canadian crude oil properties and $24.8 million on our Marcellus natural gas assets. Through our capital program in 2020, we added 16.7 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves, replacing 50% of our net production, including economic factors and technical revisions and before accounting for acquisitions and divestments.

2023 Guidance

Our capital spending guidance range is $500 - $550 million for 2023.

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


($ millions, except per BOE amounts)	2022		2021		2020
DD&A expense	$	309.4	$	271.3	$	218.1
Per BOE	$	8.45	$	8.06	$	8.16

DD&A of PP&E is recognized using the unit of production method based on proved reserves. We recorded DD&A of $309.4 million, or $8.45/BOE, during 2022, an increase compared to $271.3 million, or $8.06/BOE, in 2021. The increase in total DD&A expense and per BOE is a result of higher overall production volumes, and higher PP&E costs from the Bruin and Dunn County acquisitions.

Impairments

PP&E

Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country cost centre basis using estimated after-tax future net cash flows discounted at 10 percent from proved reserves (“Standardized Measure”), using constant prices as defined by the SEC guidelines. SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. The Standardized Measure is not related to Enerplus’ investment criteria and is not a fair value-based measurement, but rather a prescribed accounting calculation. Impairments are non-cash and are not reversed in future periods under U.S. GAAP.

20 ENERPLUS 2022 FINANCIAL SUMMARY

Trailing twelve-month average crude oil and natural gas prices have improved throughout 2021 and 2022, after falling in 2020 as a result of the impacts of the COVID-19 pandemic. There were no impairments for the twelve months ended December 31, 2022. For the twelve months ended December 31, 2021, we recorded a PP&E impairment of $3.4 million related to our Canadian assets. For the twelve months ended December 31, 2020, we recorded a PP&E impairment of $751.7 million (Canadian cost centre: $100.9 million, U.S. cost centre: $650.8 million).

Enerplus requested and received a temporary exemption from the SEC to exclude the properties acquired in the Bruin Acquisition in the U.S. full cost ceiling test for the duration of 2021.

Many factors influence the allowed ceiling value compared to our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the upcoming year, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. See "Risk Factors and Risk Management – Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets" in this MD&A.

The following table outlines the twelve-month average trailing benchmark prices and exchange rates used in our ceiling test at December 31, 2022, 2021 and 2020:


	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub			Exchange Rate
Year	$/bbl		CDN$/bbl		$/Mcf			$CDN/$US
2022	$	94.14	$	119.13	$	6.25	$	0.77
2021	$	66.55	$	78.15	$	3.64	$	0.80
2020	$	39.54	$	45.56	$	2.00	$	0.75

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is stated at cost less impairment and is not amortized or deductible for income tax purposes.

During 2020, we recorded a goodwill impairment of $149.2 million related to our U.S. reporting unit. The impairment was a result of the deterioration in macroeconomic conditions and low commodity prices due to the COVID-19 pandemic, which resulted in a reduction in fair value of the U.S. reporting unit and a full write down of our U.S. goodwill asset. At December 31, 2022 and 2021 there was no goodwill on our Condensed Consolidated Balance Sheet.

Asset Retirement Obligation (“ARO”)

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 our balance sheet is based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate, the timing of the costs to be incurred in future periods and estimates for inflation. We have estimated the net present value of our asset retirement obligation to be $114.7 million at December 31, 2022, compared to $132.8 million at December 31, 2021. The decrease in the net present value is largely due to the reduced liability in connection with the divestment of Canadian assets in 2022, offset by higher estimated costs due to high levels of inflation.

During 2022, we spent $17.4 million (2021 – $13.0 million, 2020 – $13.3 million) on our asset retirement obligations. The majority of our abandonment, reclamation and remediation costs are expected to be incurred between 2023 – 2034 and 2037 – 2053. We do not reserve cash or assets for the purpose of funding our future asset retirement obligations. Any abandonment, reclamation and remediation costs are anticipated to be funded out of adjusted funds flow and our Bank Credit Facilities.

In 2022 and 2021, Enerplus benefited from provincial government assistance to support the cleanup of inactive or abandoned crude oil and natural gas wells. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For twelve months ended December 31, 2022, Enerplus benefitted from $1.7 million (2021 – $4.6 million, 2020 – nil), in government assistance.

Leases

Enerplus recognizes Right-Of-Use (“ROU”) assets and lease liabilities on the Consolidated Balance Sheet for qualifying leases with a term greater than 12 months. We incur lease payments related to office space, drilling rig commitments, vehicles and other equipment. Total lease liabilities included on our balance sheet are based on the present value of lease payments over the lease term. Total ROU assets included on our balance sheet represent the remaining unamortized amount of our right to use an underlying asset for its remaining lease term. At December 31, 2022 our total lease liability was $22.9 million, compared to $28.9 million at December 31, 2021. At December 31, 2022 our ROU asset was $20.6 million, compared to $26.1 million at December 31, 2021.

ENERPLUS 2022 FINANCIAL SUMMARY 21

Income Taxes


($ millions)	2022		2021		2020
Current tax expense/(recovery)	$	28.1	$	2.7	$	(10.7)
Deferred tax expense/(recovery)		265.2		98.8		(188.3)
Total tax expense/(recovery)	$	293.3	$	101.5	$	(199.0)

In 2022, we recorded a current tax expense of $28.1 million or 2% of adjusted funds flow before tax in line with our revised guidance of 2-3% of adjusted funds flow before tax, compared to an expense of $2.7 million in 2021 and a recovery of $10.7 million in 2020. The increase in expense in 2022, compared to 2021, is due to additional U.S. federal and state tax resulting from higher net income for the year and the utilization of our net operating loss carryforward. The recovery in 2020 was related to the recognition of our final U.S. Alternative Minimum Tax ("AMT") refund.

In 2022, we recorded a deferred income tax expense of $265.2 million compared to an expense of $98.8 million in 2021 and a recovery of $188.3 million in 2020. The expense in 2022 and 2021 is primarily due to higher U.S. income. The deferred tax recovery in 2020 was due to net losses in 2020 from non-cash PP&E impairments in both the U.S. and Canada cost centres.

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 a 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 year ended December 31, 2022, no valuation allowance was recorded against our Canadian income related deferred tax asset, however, a full valuation allowance has been recorded against our deferred income tax assets related to capital items. Our deferred income tax asset recorded in Canada is $155.0 million offset by a deferred income tax liability in the U.S. of $55.4 million as at December 31, 2022 (December 31, 2021 - $380.9 million net asset).

Our estimated tax pools at December 31, 2022 are as follows:


Pool Type ($ millions)	2022
U.S.
Depletable and depreciable assets	$	1,010
	$	1,010
Canada
Non-capital losses and other credits	$	500
Canadian exploration expense		140
Canadian development expense		17
Undepreciated capital costs		21
	$	678
Total tax pools and credits	$	1,688

2023 Guidance

Our current tax guidance is 5 - 6% of adjusted funds flow before tax for 2023, assuming WTI of $80.00/bbl and NYMEX of $3.50/Mcf.

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess our 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 EBITDA¹”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At December 31, 2022, our senior debt to adjusted EBITDA ratio was 0.2x and our net debt to adjusted funds flow ratio was 0.2x. Although a capital management measure that is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate our liquidity.

22 ENERPLUS 2022 FINANCIAL SUMMARY

Net debt at December 31, 2022 decreased to $221.5 million, compared to $640.4 million at December 31, 2021. Total debt was comprised of our senior notes and Bank Credit Facilities, totaling $259.5 million, less cash on hand of $38.0 million. At December 31, 2022, through our Bank Credit Facilities, we had total credit capacity of $1.3 billion, of which $56.3 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.

Our reinvestment rate was 35% for 2022 compared to 42% in 2021.

During 2022, a total of $452.5 million, representing 57% of free cash flow¹, was returned to shareholders through share repurchases and dividends, compared to $153.7 million in 2021. In 2022, a total of 27,924,842 common shares were repurchased under the NCIB at an average price of $14.71 per share (December 31, 2021 – 12,897,721 shares, $9.55 per share). Subsequent to December 31, 2022 and up to and including February 22, 2023, we repurchased 1,420,927 common shares under the NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

For the year ended December 31, 2022, Enerplus increased its quarterly dividend three times resulting in a 67% increase to $0.055 per common share and paid a total of $41.6 million (December 31, 2021 – $30.5 million).

During the first quarter of 2022, Enerplus converted its senior unsecured, covenant-based, $400 million term loan maturing on March 9, 2024 into a revolving bank credit facility with no other amendments. During the fourth quarter of 2022, Enerplus converted this revolving bank credit facility to a $365 million SLL bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility, which was renewed with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the two agreements’ terms or covenants.

The SLL Bank Credit Facilities incorporate environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company:

●

GHG Emissions: continuous progress toward Enerplus’ stated goal of a 35% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2021 as a baseline and measurement based on Enerplus’ annual internal targets;

●

Water Management: achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019; and

●

Health & Safety: achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline.

At December 31, 2022, 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 Company may be exceeded with no ability to negotiate covenant relief" in the Annual Information Form. Agreements relating to our Bank Credit Facilities and senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.

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

ENERPLUS 2022 FINANCIAL SUMMARY 23

The following table lists our financial covenants, as defined by our debt agreements, at December 31, 2022:


Covenant Description		December 31, 2022
Bank Credit Facilities:	Maximum Ratio
Senior debt to adjusted EBITDA	3.5x	0.2x
Total debt to adjusted EBITDA	4.0x	0.2x
Total debt to capitalization	55%	13%

Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA⁽¹⁾	3.0x - 3.5x	0.2x
Senior debt to consolidated present value of total proved reserves⁽²⁾	60%	6%

	Minimum Ratio
Adjusted EBITDA to interest	4.0x	54.3x

Definitions

“Senior Debt” is calculated as the sum of drawn amounts on our Bank Credit Facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the twelve months ended December 31, 2022 was $1,332.6 million.

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

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

Footnotes

(1)	Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(2)	Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

Counterparty Credit

CRUDE OIL AND NATURAL GAS SALES COUNTERPARTIES

Our crude oil and natural gas receivables are with customers in the oil and gas industry and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. A credit review process is in place to assess and monitor our counterparties’ creditworthiness on a regular basis. This process involves reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted, we obtain financial assurances such as letters of credit, parental guarantees or third-party insurance to mitigate a portion of our credit risk. This process is utilized for both our crude oil and natural gas sales counterparties as well as our financial derivative counterparties.

FINANCIAL DERIVATIVE COUNTERPARTIES

We are exposed to credit risk in the event of non-performance by our financial counterparties regarding our derivative contracts. We mitigate this risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association (“ISDA”) agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other under all outstanding transactions and settle with a single net amount in the case of a credit event. To date we have not experienced any losses due to non-performance by our derivative counterparties. All of our derivative counterparties are considered investment grade. At December 31, 2022, we had $36.5 million in financial derivative assets offset by $10.4 million of financial derivative liabilities resulting in a net asset position of $26.1 million (December 31, 2021 – assets of $5.7 million, offset by liabilities of $150.3 million, resulting in a net liability position of $144.6 million).

Dividends


($ millions, except per share amounts)	2022		2021		2020
Dividends⁽¹⁾	$	41.6	$	30.5	$	20.0
Per weighted average share (Basic)	$	0.181	$	0.121	$	0.090

(1)	Excludes changes in non-cash financing working capital.

During 2022, we declared dividends of $0.181 per weighted average common share totaling $41.6 million (2021 – $0.121 per share and $30.5 million; 2020 – $0.090 per share and $20.0 million).

In 2022, we declared a quarterly dividend of $0.033 per common share for the first quarter, $0.043 per common share for the second quarter, $0.050 per common share for the third quarter, and $0.055 per common share for the fourth quarter. Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share to be paid in March 2023.

24 ENERPLUS 2022 FINANCIAL SUMMARY

We expect to fund the dividend through the free cash flow generated by the business. The dividend is a part of our strategy to return capital to shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital


	2022		2021		2020
Share capital ($ millions)	$	2,837.3	$	3,094.1	$	3,113.8

Common shares outstanding (thousands)		217,285		243,852		222,548
Weighted average shares outstanding – basic (thousands)		233,946		251,909		222,503
Weighted average shares outstanding – diluted (thousands)		242,673		259,851		222,503

For the twelve months ended December 31, 2022, a total of 2,411,783 units vested pursuant to our treasury settled LTI plans (2021 – 2,014,193; 2020 – 2,044,718). In total, 1,358,000 common shares were issued from treasury and $10.0 million was transferred from paid-in capital to share capital (2021 – 1,140,000 and $9.4 million; 2020 – 1,160,000 and $10.7 million). We elected to cash settle the remaining units related to the required tax withholdings (2022 - $13.4 million, 2021 – $3.6 million, 2020 – $5.6 million).

In July 2022, Enerplus completed its previous NCIB by repurchasing 10% of its outstanding shares. On August 16, 2022, Enerplus renewed its NCIB to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange rules) during the following 12-month period. As a result, in 2022, 27,924,842 common shares were repurchased and cancelled under the NCIB at an average price of $14.71 per common share, for total consideration of $410.9 million. Of the amount paid, $266.7 million was charged to share capital and $144.2 million was added to accumulated deficit. At December 31, 2022, 7,883,479 common shares were available for repurchase under the current NCIB.

Subsequent to December 31, 2022 and up to and including February 22, 2023, we repurchased 1,420,927 common shares under the NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

As of February 22, 2023, we had 216,479,610 common shares outstanding. In addition, an aggregate of 9,699,445 common shares may be issued to settle outstanding grants under our share award incentive plan (in the form of PSUs and RSUs), assuming the maximum payout multiplier of 2.0 times for the PSUs.

Commitments and Contingencies

We have the following minimum annual contractual commitments:


													Total
			Minimum Annual Commitment Each Year										Committed
($ millions)	Total		2023		2024		2025		2026		2027		after 2027
Senior notes⁽¹⁾	$	203.2	$	80.6	$	80.6	$	21.0	$	21.0	$	—	$	—
Transportation commitments		487.6		71.3		72.6		73.4		74.0		61.9		134.4
Service workover rigs commitments		7.9		7.9		—		—		—		—		—
Operating lease obligations		24.0		14.3		6.5		1.1		1.0		1.0		0.1
Purchase commitments		2.1		2.1		—		—		—		—		—
Total commitments⁽²⁾⁽³⁾	$	724.8	$	176.2	$	159.7	$	95.5	$	96.0	$	62.9	$	134.5

(1)	Interest payments have not been included.

(2)	Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(3)	CDN$ commitments have been converted to US$ using the December 31, 2022 foreign exchange rate of 0.74.

In the Marcellus, we have firm transportation agreements in place for approximately 64,900 Mcf/day of gross natural gas volumes, which expire between 2023 and 2036. This includes an agreement for firm pipeline capacity on the Tennessee Gas Pipeline from our Marcellus producing region to downstream connections for 30,000 Mcf/day of gross natural gas volumes until mid-2027, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of $62.7 million through 2036. In the Bakken region, we hold firm pipeline capacity to transport a portion of our crude oil production to the U.S. Gulf Coast, which expires in early 2029 as well as mid-2031.

We have firm commitments in place for the operation of service workover rigs for $7.9 million for 2023.

ENERPLUS 2022 FINANCIAL SUMMARY 25

SELECTED ANNUAL U.S. AND CANADIAN FINANCIAL RESULTS


	Year ended December 31, 2022							Year ended December 31, 2021
($ millions, except per unit amounts)		U.S.		Canada		Total		U.S.		Canada		Total
Average Daily Production Volumes
Crude oil (bbls/day)			47,511		4,506		52,017		42,981		5,533		48,514
Natural gas liquids (bbls/day)			9,439		242		9,681		7,500		323		7,823
Natural gas (Mcf/day)			225,667		6,103		231,770		207,242		8,062		215,304
Total average daily production (BOE/day)			94,561		5,765		100,326		85,021		7,200		92,221

Pricing⁽¹⁾
Crude oil (per bbl)		$	94.94	$	79.83	$	93.63	$	67.30	$	55.00	$	65.89
Natural gas liquids (per bbl)			30.11		53.90		30.70		29.20		36.80		29.51
Natural gas (per Mcf)			5.53		4.90		5.51		2.90		3.78		2.94

Property, Plant and Equipment
Capital and office expenditures		$	426.5	$	6.8	$	433.3	$	289.5	$	14.4	$	303.9
Property and land acquisitions			21.3		1.2		22.5		832.8		2.3		835.1
Property and land divestments			(18.4)		(213.0)		(231.4)		(108.0)		(4.7)		(112.7)

Netback Before Impact of Commodity Derivative Contracts⁽²⁾
Crude oil and natural gas sales		$	2,205.9	$	147.5	$	2,353.4	$	1,355.3	$	127.3	$	1,482.6
Operating expenses			(324.9)		(40.8)		(365.7)		(250.7)		(41.7)		(292.4)
Transportation costs			(150.0)		(4.7)		(154.7)		(122.2)		(6.1)		(128.3)
Production taxes			(164.4)		(2.6)		(167.0)		(99.9)		(2.1)		(102.0)
Netback before impact of commodity derivative contracts		$	1,566.6	$	99.4	$	1,666.0	$	882.5	$	77.4	$	959.9

Other Expenses
Commodity derivative instruments loss/(gain)			—		197.7		197.7		—		274.4		274.4
General and administrative expense⁽³⁾			42.4		27.6		70.0		35.4		21.4		56.8
Current income tax expense/(recovery)			28.1		—		28.1		2.7		—		2.7

(1)	Before transportation costs and the effects of commodity derivative instruments.

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

(3)	Includes share-based compensation.

THREE YEAR SUMMARY OF KEY MEASURES


($ millions, except per share amounts)	2022		2021		2020
Crude oil and natural gas sales	$	2,353.4	$	1,482.6	$	553.7

Net income/(loss)		914.3		234.4		(693.4)
Per share (Basic)		3.91		0.93		(3.12)
Per share (Diluted)		3.77		0.90		(3.12)

Adjusted net income⁽¹⁾		707.1		315.7		14.5

Cash flow from operating activities		1,173.4		604.8		335.9
Adjusted funds flow		1,230.3		712.4		265.5

Dividends⁽²⁾		41.6		30.5		20.0
Per share (Basic)⁽²⁾		0.181		0.121		0.090
Total assets		1,938.0		1,990.1		1,152.4
Total debt		259.5		701.8		385.4

Net debt		221.5		640.4		295.5
Total non-current financial liabilities		358.2		759.3		424.6

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

(2)	Calculated based on dividends paid and/or payable.

26 ENERPLUS 2022 FINANCIAL SUMMARY

2022 versus 2021

Crude oil and natural gas sales were $2,353.4 million in 2022 compared to $1,482.6 million in 2021. We reported net income of $914.3 million in 2022 compared to a net income of $234.4 million in 2021. The increases were due to higher realized commodity prices and increased production from the acquisitions in North Dakota completed during the first half of 2021, increased completions activity in North Dakota and the Marcellus, and the gain on the sale of Canadian assets.

Cash flow from operating activities and adjusted funds flow increased to $1,173.4 million and $1,230.3 million, respectively, in 2022 from $604.8 million and $712.4 million in 2021. The increase was primarily the result of a $870.8 million increase in crude oil and natural gas sales due to higher realized commodity prices and higher production.

2021 versus 2020

Crude oil and natural gas sales were $1,482.6 million in 2021 compared to $553.7 million in 2020. We reported net income of $234.4 million in 2021 compared to a net loss of $693.4 million in 2020. The increases were due to higher realized commodity prices and increased production from the Bruin and Dunn County acquisitions as well as lower non-cash impairments in 2021 compared to 2020.

Cash flow from operating activities and adjusted funds flow increased to $604.8 million and $712.4 million, respectively, in 2021 from $335.9 million and $265.5 million in 2020. The increase was primarily the result of a $928.8 million increase in crude oil and natural gas sales due to higher realized commodity prices and higher production.

QUARTERLY FINANCIAL INFORMATION


	Crude Oil and		Net		Net Income/(Loss) Per Share
($ millions, except per share amounts)	Natural Gas Sales		Income/(Loss)		Basic		Diluted
2022
Fourth Quarter	$	548.7	$	330.7	$	1.49	$	1.43
Third Quarter		663.5		305.9		1.32		1.28
Second Quarter		628.0		244.4		1.01		0.99
First Quarter		513.2		33.2		0.14		0.13
Total 2022	$	2,353.4	$	914.3	$	3.91	$	3.77
2021
Fourth Quarter	$	499.7	$	176.9	$	0.71	$	0.68
Third Quarter		421.1		98.1		0.38		0.38
Second Quarter		333.4		(50.9)		(0.20)		(0.20)
First Quarter		228.4		10.3		0.04		0.04
Total 2021	$	1,482.6	$	234.4	$	0.93	$	0.90

During 2022, crude oil and natural gas sales increased due to higher production and improved realized pricing. Net income decreased during the first quarter of 2022 due to a $206.8 million loss recorded on commodity derivative instruments as a result of higher commodity prices. Net income increased during the second quarter of 2022 due to a smaller loss recorded on commodity derivative instruments of $47.6 million. During the second half of 2022, net income increased due to a commodity derivative instruments gain of $57.0 million in the third quarter of 2022, and $151.9 million gain on the sale of the Canadian assets in the fourth quarter of 2022.

During 2021, crude oil and natural gas sales increased due to improvements in commodity prices in the first quarter. During the second quarter, crude oil and natural gas sales increased due to higher production from the Bruin and Dunn County acquisitions. The net loss in the same period was primarily due to commodity derivative instrument losses as a result of the higher commodity prices as crude oil demand continued to improve. During the second half of 2021, commodity prices continued to increase, and additional wells came on production which resulted in higher net income.

ENERPLUS 2022 FINANCIAL SUMMARY 27

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (“ESG”)

Enerplus believes that minimizing the environmental impacts of its operations is a foundational tenet of corporate responsibility. Moreover, as the global economy transitions to a lower carbon future, climate related policies and regulations around carbon emissions are becoming increasingly stringent, requiring businesses to adapt to support long-term business resilience. We intend to continue to improve energy efficiencies and proactively manage our environmental impact in compliance with applicable government regulations, including regulations enacted at the provincial, state and federal jurisdictions in which we operate.

Our Board of Directors is responsible for overseeing our ESG-related risks and initiatives. Specific accountability for our five material focus areas have been mapped to the relevant Board committees, including the Compensation and Human Resources Committee, and the Reserves, Safety and Social Responsibility Committee (the “RS&SR Committee”).The five material focus areas are:

●

Emissions Management

●

Water Management

●

Culture

●

Community Engagement

●

Health and Safety

As part of our continued integration of ESG issues into our business strategy and operations, in 2022 we updated targets for reducing Scope 1 and Scope 2 GHG emissions and methane emissions intensities. Using 2021 as a baseline, we targeted a 30% reduction of our methane emissions intensity per BOE by the end of 2025, and a 50% reduction by 2030. We have revised our long-term GHG emissions reduction target of reducing our Scope 1 and Scope 2 emissions intensity by 35% by 2030 relative to our 2021 baseline. During 2022, we reduced our methane emissions intensity by 9% and reduced 2022 Scope 1 and Scope 2 GHG emissions intensity by approximately 16%, based on preliminary estimates, from our 2021 baseline. Final results will be available in our annual ESG Report and Data Tables, expected to be published later in 2023.

We set a Health & Safety target of reducing our Lost Time Injury Frequency (“LTIF”) by 25%, on average, from 2020 to 2023, relative to a 2019 baseline. In 2022, we reported an LTIF of 0.06 injuries per 200,000 worker hours, down from 0.08 in 2019. We will continue to update the market as we progress closer to the end of our 2023 target.

We have a Health & Safety Policy (“H&S Policy”) and an Environmental, Social and Governance Policy (“ESG Policy”), which articulate our commitment to health and safety, community engagement, environmental and regulatory compliance, and social and governance practices. Our Board of Directors and President & Chief Executive Officer are ultimately accountable for overseeing compliance with these policies. The RS&SR Committee of our Board of Directors is responsible for overseeing our H&S performance and safety and social responsibility risks. The Board of Directors are responsible for overseeing our ESG performance, risks and strategy. We believe that this governance structure promotes adequate systems in place to support ongoing compliance, and to plan the Company’s activities in a safe, socially responsible and sustainable manner.

The RS&SR Committee regularly reviews health, safety, environmental and regulatory updates, and risks. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and we have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations. However, increased capital and operating costs may be incurred if regulations impose more stringent compliance requirements.

Annually, we publish an ESG Report in accordance with the Sustainability Accounting Standards Boards (“SASB”) Oil and Gas – Exploration and Production Standard materiality map, the Global Reporting Initiative (“GRI”) Core option, and the International Petroleum Industry Environmental Conservation Association’s (“IPIECA”) “Oil and gas industry guidance on voluntary sustainability reporting” (a joint publication with the American Petroleum Institute and the International Association of Oil & Gas Producers). Additionally, in conjunction with our ESG Report, we publish a Reporting Table based on recommendations of the Task Force on Climate Related Financial Disclosure (“TCFD”). Our ESG report summarizes our approach to and performance related to environmental, safety, social responsibility and governance performance, and can be found on our website at www.enerplus.com. In 2022, Enerplus underwent an external audit of selected ESG metrics representing its public targets. Enerplus received Limited Assurance on its absolute Scope 1 and 2 emissions, Scope 1 and 2 emissions intensities, produced water inclusion in completions activities, and LTIF. In 2022, we published metrics in line with the American Exploration and Production Council ESG Framework, which can also be found on our website.

28 ENERPLUS 2022 FINANCIAL SUMMARY

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital expenditures. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

Crude Oil and Natural Gas Properties and Reserves

Enerplus follows the full cost method of accounting for crude oil and natural gas properties. The process of estimating reserves is critical in determining several accounting estimates including the Company’s depletion, ceiling test, valuation allowance on deferred income tax assets, gain or loss calculations that may arise upon disposition of crude oil and natural gas properties and purchase equations associated with business combinations. The estimation of crude oil and natural gas reserves and the related present value of future cash flows involves the use of independent reservoir engineering specialists and numerous estimates and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Estimating reserves requires significant judgments based on available geological, geophysical, engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and natural gas prices, operating costs and royalty burdens change. Reserves estimates impact net income through depletion, the determination of asset retirement obligation and the application of impairment tests. Revisions or changes in reserves estimates can have either a positive or a negative impact on net income.

Asset Impairment

Ceiling Test

Under the full cost method of accounting for PP&E, we are subject to quarterly calculations of a ceiling or limitation on the amount of our crude oil and natural gas properties that can be capitalized on our balance sheet by cost centre. If the net capitalized costs of our crude oil and natural gas properties exceed the cost centre ceiling, we are subject to a ceiling test write-down to the extent of such excess. These write-downs reduce net income and impact shareholders’ equity in the period of occurrence and result in lower depletion expense in future periods. The volume and discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of crude oil and natural gas that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average crude oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our crude oil and natural gas properties could occur in the future. Under U.S. GAAP impairments are not reversed in future periods.

Income Taxes

Management makes certain estimates in calculating deferred tax assets and liabilities, as well as income tax expense. These estimates often involve judgment regarding differences in the timing and recognition of revenue and expense for tax and financial reporting purposes as well as the tax basis of our assets and liabilities at the balance sheet date before tax returns are completed. Additionally, we must assess the likelihood we will be able to recover or utilize our deferred tax assets. We must record a valuation allowance against a deferred tax asset where all or a portion of that asset is not expected to be realized. In evaluating whether a valuation allowance should be applied, we consider evidence such as future taxable income, among other factors, both positive and negative. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely than not that the asset will be realized.

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon, reclaim and remediate its ownership interest in all wells, facilities and pipelines, the estimated timing of the costs to be incurred in future periods and the appropriate credit adjusted risk free rate. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and depleted over its useful life. There are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserves estimates, costs and technology.

ENERPLUS 2022 FINANCIAL SUMMARY 29

Business Combinations

Management makes various assumptions in determining the fair value of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the crude oil and natural gas properties. To determine the fair value of these properties, we, and independent evaluators, estimate crude oil and natural gas reserves and future prices of crude oil and natural gas.

Derivative Financial Instruments

We utilize derivative financial instruments to manage our exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates.

The fair value of commodity contracts and the equity swaps is estimated based on commodity and option pricing models that incorporate various factors including forecasted commodity prices, volatility and the credit risk of the entries party to the contract. Changes and variability in commodity prices over the term of the term of the contracts can result in material differences between the estimated fair value at a point in time and the actual settlement amounts. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates, discount rates used to present value the instrument and counterparty credit risk.

RISK FACTORS AND RISK MANAGEMENT

Commodity Price Risk

Our operating results and financial condition are dependent on the prices we receive for our crude oil, natural gas liquids, and natural gas production. These prices have fluctuated widely in response to a variety of factors including:

●

global and domestic supply and demand of crude oil, natural gas and natural gas liquids

●

actions taken by OPEC+ or non-OPEC+ members to set, maintain or alter production levels

●

the ability to export from North America

●

geopolitical uncertainty, including the ongoing conflict in Ukraine

●

sustained pandemics or epidemics, including the continuing effect of the COVID-19 pandemic, which may disrupt economies, whether local or global, and may impact supply, demand and prices for crude oil, natural gas liquids and natural gas

●

global gross domestic product growth

●

the level of consumer demand, including demand for different qualities and types of crude oil, natural gas liquids and natural gas

●

the production and storage levels of global crude oil, natural gas and natural gas liquids

●

supply chain challenges and disruptions

●

weather conditions

●

proximity of reserves and resources to, and capacity of, gathering and transportation facilities, and the availability of refining, processing and fractionation capacity

●

the effect of world-wide energy conservation and greenhouse gas reduction measures

●

the price and availability of alternative fuels

●

existing and proposed changes to government regulations and policy decisions, including moratoriums with respect thereto

A future decline in crude oil or natural gas prices may have a material adverse effect on our operations and cash flows, financial condition, borrowing ability, levels of reserves and resources and the level of capital expenditures available for the development of our crude oil and natural gas reserves or resources. Certain oil or natural gas wells may become or remain uneconomic to produce if commodity prices are low, thereby impacting our production volumes, or our desire to market our production in when market conditions are less satisfactory for Enerplus. Furthermore, we may be subject to the decisions of third-party operators or to legislative decisions by regional governments who, independently and using different economic parameters, may decide to curtail or shut-in jointly owned production or to mandate industry-wide production curtailments.

We may use financial derivative instruments and other commodity derivative mechanisms to help limit the adverse effects of crude oil, natural gas liquids, and natural gas price volatility. However, we do not have commodity contracts in place for all our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial derivative instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase. As of February 22, 2023, we have 15,000 bbls/day hedged for first half of 2023 and 5,000 bbls/day hedged for the second half of 2023. We have also hedged 120,000 Mcf/day for the period from January 1, 2023 to March 31, 2023 and 50,000 Mcf/day for the period from April 1, 2023 to October 31, 2023. Refer to the “Price Risk Management” section for further details on our price risk management program.

30 ENERPLUS 2022 FINANCIAL SUMMARY

Risks Relating to the Impact of the Ukraine and Russia conflict

The existing conflict between Ukraine and Russia and the international response has, and may continue to have, potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Certain countries including Canada, the United States, Australia and certain European countries have imposed strict financial and trade sanctions against Russia, which may have continued far-reaching effects on the global economy, energy and commodity prices and food security and crop nutrient supply and prices. The short-, medium- and long-term implications of the conflict in Ukraine are difficult to predict with any degree of certainty at this time. Depending on the extent, duration, and severity of the conflict, it may have the effect of heightening many of the other risks described in our Annual MD&A and our Annual Information Form, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of capital; and supply chains and cost effective and timely transportation.

Risk of Increasing Attention to ESG and Sustainability Matters

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices. These standards are evolving, and if we fail to comply with these standards or are perceived to have not responded appropriately to these standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and the business, financial condition, and/or stock price could be materially and adversely affected. Increasing attention to climate change and sustainability, increasing societal expectations on companies to address climate change-related targets, and potential consumer use of substitutes to fossil-fuel energy commodities may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts to our stock price and access to capital markets. Increasing attention to climate change-related and sustainability targets and expected actions, for example, may result in demand shifts for hydrocarbon products and additional governmental investigations and private litigation against Enerplus.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of the Corporation’s shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of the Corporation's operations by certain investors. Additionally, to the extent ESG matters negatively impact the Corporation’s reputation, it may not be able to compete as effectively to recruit or retain employees, which may adversely affect its operations.

The Corporation also makes certain disclosures regarding sustainability, publishing an ESG report that provides updates on its performance related to certain ESG topics and sets certain ESG goals. Many of its disclosures are necessarily based on estimates and assumptions that are inherently difficult to assess. Moreover, Enerplus may not be able to adequately identify ESG-related risks and opportunities and, further, may not be able to meet ESG targets in the manner, or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. While the Corporation may elect to seek out various additional voluntary ESG targets now or in the future, such targets are aspirational. Notwithstanding this, Enerplus may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but it cannot guarantee it will be able to implement such goals because of potential costs or technical or operational obstacles.

Additionally, public statements with respect to emissions reduction goals, environmental targets, or, more broadly, ESG-related goals, are becoming increasingly subject to heightened scrutiny from public and governmental authorities with respect to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. The Canadian securities regulators (the “CSA”) have been monitoring issuers’ disclosures relating to various ESG-related matters and have published a public guidance stating their concerns with certain practices involving unsupported claims that may constitute greenwashing. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, to include emission reduction goals or standards used, were misleading, false, or otherwise deceptive. As a result, the Corporation may face increased litigation risks which could, in turn, lead to further negative sentiment and diversion of investments. Enerplus could also face increasing costs to comply with increased regulatory focus and scrutiny.

ENERPLUS 2022 FINANCIAL SUMMARY 31

Regulatory Risk and Greenhouse Gas Emissions

Government royalties, environmental laws and regulatory requirements can have a significant financial and operational impact on us. As an oil and gas producer, we operate under federal, provincial, state, tribal and municipal legislation and regulation that govern such matters as royalties, land tenure, prices, production rates, various environmental protection controls, well and facility design and operation, income taxes, the gathering, transportation and the exportation of crude oil, natural gas and other products. We may be required to apply for regulatory approvals in the ordinary course of business. To the extent that we fail to comply with applicable government regulations or regulatory approvals, we may be subject to compliance and enforcement actions that are either remedial or punitive to deter future noncompliance. Such actions include penalties, fines or fees, notices of noncompliance, warnings, orders, curtailment, administrative sanctions and prosecution.

Government regulations may be changed from time to time in response to economic, political or socioeconomic conditions, including the election of new state, provincial or federal leaders. Additionally, our entry into new jurisdictions or adoption of new technology may attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. U.S. federal and state governments continue to scrutinize emissions, as well as the usage and disposal of chemicals and water used in fracturing procedures in the oil and gas industry; certain states have called for bans on oil and gas drilling using hydraulic fracturing and the new U.S. administration has taken actions towards fulfilling its initiative of curtailing hydraulic fracturing of federal lands. Additionally, various levels of U.S. and Canadian governments are considering or have implemented legislation to reduce emissions of greenhouse gases, including volatile organic compounds (“VOC”) and methane gas emissions.

The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations could negatively impact the development of crude oil and natural gas properties and assets, reduce demand for crude oil and natural gas or impose increased costs on oil and gas companies including taxes, fees or other penalties.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas by participating in industry organizations, conferences, exchanging information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results. Accordingly, while we continue to prepare to meet the potential requirements at each of the provincial, state, federal, tribal and municipal levels, the actual cost impact and its materiality to our business remains uncertain.

Risks Relating to Climate Change

Enerplus is subject to climate change related risks which are generally grouped into two categories: physical risks and transition risks. Physical risks include the impact that a change in climate could have on our operations, facilities and infrastructure, including limited water availability, severe weather causing flooding, prolonged drought and/or wildfires. These events may increase the cost of water, energy, insurance or capital projects, impacting our profitability. The physical risks of climate change may also result in operational delays, depending on the nature of the event. Enerplus does not believe that its current or near-term operations expose it to any particular physical risks which differ from those facing a typical North American onshore oil and gas producer, and currently cannot predict or quantify the potential financial impact of any such risks.

Transition risk is broader and relates to the consequences of a global transition to reduced carbon economy, including the risk of regulatory and policy change and reputational concerns. The global push to meet net zero emission targets by 2050 increases the risk of potentially burdensome regulatory and/or policy changes from governments, some of which could have a direct, negative impact on Enerplus should they impede access or negatively impact our relationship with our stakeholders, debt holders, insurers, and the investment community or various service providers. In addition, as a result of these regulations and policies, Enerplus could also have stranded assets, for example, be unable to obtain value for, or from, its reserves.

More specific concerns of the fossil fuels, for the industry relate to GHG emissions, including methane, as well as water and land use. More stringent legislation or regulations in the United States and Canada, relative to other jurisdictions, including requirements to significantly reduce GHG emissions, water consumption or setback requirements for facilities and wells, could result in increased costs and competitive disadvantages. In addition, a potential increase in capital expenditures, operating expenses, abandonment and reclamation obligations or the loss of operating licenses, any of which may not be recoverable in the marketplace, could result in operations or growth projects becoming less profitable, uneconomic, or result in our inability to continue development of assets.

32 ENERPLUS 2022 FINANCIAL SUMMARY

There is also a risk that financial institutions will adopt, or be pressured, or be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector; both the Bank of Canada and the Federal Reserve of the United States have joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. As a result of new initiatives, we could be required to adopt new technologies, and make a significant investment in capital resources. These initiatives could also result in additional costs if climate-related targets are not achieved, therefore negatively impacting our results and economics. The CSA and the SEC have separately released proposed rules that would establish a framework for the reporting of climate risks, targets, and metrics. Although the final form and substance of this rule and its requirements are not yet known, and the ultimate impact on the Corporation is uncertain, the proposed rule, if finalized, may result in increased compliance costs and increased costs of and restrictions on access to capital.

There is also a reputational risk associated with climate change, which considers the public perception of Enerplus’ role in the transition to a low carbon economy. We seek to mitigate this risk through a strong ESG program with six material focus areas which are overseen by our Board of Directors and applicable Board committees. Our strategy is to be a responsible operator from the perspective of our shareholders, employees, contractors, regulators, lenders, communities and the general public. Despite these efforts, activities undertaken directly by Enerplus or its employees in operating its business, or by others in industry, could adversely affect Enerplus’ reputation. If our reputation, or the oil and gas industry in general, is diminished, it could result in: the loss of employees or revenue; delays in regulatory approvals; increased operating, capital, financing and regulatory costs; reduced shareholder confidence and negative stock price movement; negative relationships with Indian Reservations and Indigenous groups; or a loss of public support in general.

Cyber Security Risks

We are subject to a variety of information technology and system risks as part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach and destruction or interruption of our information technology systems by third parties or insiders. Additionally, use of personal devices can create further avenues for potential cyber-related incidents, as we have little or no control over the safety of these devices. Information technology and cyber risks have increased since the COVID-19 pandemic and the Russia and Ukraine conflict, with cybercriminals taking advantage of remote working environments to increase malicious activities creating more threats for cyberattacks. These include phishing emails, malware-embedded mobile apps that purport to track infection rates and targeting of vulnerabilities in remote access platforms. Although we have security measures and controls in place that are designed to mitigate these risks, the growing use of the digital space could increase technological risks (example, by monitoring/intercepting phones and communications, or surveilling or locating persons of interest) further increasing the risk of a breach of our security, which could result in business interruptions, service disruptions, financial loss, theft of intellectual property and confidential information, litigation, enhanced regulatory attention and penalties, as well as reputational damage. Furthermore, the adoption of emerging technologies, such as cloud computing, artificial intelligence and robotics, call for continued focus and investment to manage risks effectively. Not managing this risk effectively may have an adverse effect and, therefore, may increase the risk of financial or reputational loss. In addition, third-party operators on whom we depend on, and the operations of our customers and business partners are also subject to such risks. The significance of any such event is difficult to quantify but may be material in certain circumstances and could have a material effect on our business, financial condition and results of operations.

Risk of Increased Capital or Operating Costs

Higher capital or operating costs associated with our operations will directly impact our capital efficiencies and cash flow. Capital costs of completions, specifically the costs of steel, proppant, pumper services, and operating costs such as electricity, chemicals, supplies, processing charges, energy services and labour costs, are a few of the costs that are susceptible to material fluctuation. Although we have a portion of our current capital and operating costs protected with existing agreements, changing regulatory conditions, such as potential new or revised regulations in the U.S. requiring certain raw materials, such as steel, for use on certain projects to be sourced from the U.S., or that goods and/or services be procured from specific vendors or classes of vendors on certain projects, other supply chain challenges or disruptions and adverse effects of inflation and rising interest rates, may result in higher than expected supply costs. Additionally, we have certain service contracts tied to inflationary measure benchmarks (such as the Consumer Price Index and WTI crude oil price), which have increased and could further increase our operating costs should the benchmarks rise significantly.

Access to Field Services

Our ability to drill, complete and tie-in wells in a timely manner may be impacted by our access to service providers and supplies. Service providers, including those we rely on, are also in a highly competitive environment that is impacted by worker availability, commodity prices and global supply inventories. Where worker availability is impacted by shortages, due to location or pandemic related issues, for example, some may choose or be required to streamline or discontinue their business, further reducing the supply of vendors and potentially increasing the competition for service/supplies, and thereby the costs to producers. Activity levels in each area may limit our access to these resources, restricting our ability to execute our capital plans in a timely manner. In addition, field service costs are influenced by market conditions and therefore can become cost prohibitive.

ENERPLUS 2022 FINANCIAL SUMMARY 33

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services through 2023, access to field services and supplies in other areas of our business will continue to be subject to market availability.

Anticipated Benefits of Acquisitions or Divestments

From time to time, we may acquire additional crude oil and natural gas properties and related assets. Achieving the anticipated benefits of such acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures, and personnel in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities from combining and integrating the acquired assets and properties into our existing business. These activities will require the dedication of substantial management effort, time, capital, and other resources, which may divert management's focus, capital and other resources from other strategic opportunities and operational matters during this process. The risk factors specified in this MD&A relating to the crude oil and natural gas business and our operations, reserves and resources apply equally to future properties or assets that we may acquire. We conduct due diligence in connection with acquisitions, but there is no assurance that we will identify all the potential risks and liabilities related to such properties.

When acquiring assets, we are subject to inherent risks associated with predicting the future performance of those assets. We may make certain estimates and assumptions respecting the characteristics of the assets we acquire, that may not be realized over time. As such, assets acquired may not possess the value we attribute to them, which could adversely impact our future cash flows. To the extent that we make acquisitions with higher growth potential, the higher risks often associated may result in increased chances that actual results may vary from our initial estimates. An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods, approaches, and assumptions than those of our engineers, and these initial assessments may differ significantly from our subsequent assessments. There is also no assurance that the acquired assets will be viewed favourably by our investors and could result in a negative effect to the price of our common shares.

Certain acquisitions, and in particular acquisitions of higher risk/higher growth assets and the development of those acquired assets, may require capital expenditures and we may not receive cash flow from operating activities from these acquisitions for several years, or in amounts less than anticipated. Accordingly, the timing and amount of capital expenditures may adversely affect our cash flow.

We may also seek to divest of properties and assets from time to time. These divestments may consist of non-core properties or assets, or may consist of assets or properties that are being monetized to fund alternative projects or development or debt repayments. There can be no assurance that we will be successful, that we will realize the amount of desired proceeds, or that such divestments will be viewed positively by the financial markets. Divestments may negatively affect our results of operations or the trading price of our common shares. In addition, although divestments typically transfer future obligations to the buyer, we may not be exempt from certain future obligations, including abandonment, reclamation, and/or remediation if applicable, which may have an adverse effect on our operations and financial condition.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through issuance of equity and debt in past years. Continued access to capital is dependent on our ability to optimize our existing assets and to demonstrate the advantages of the acquisition or development program that we are financing at the time, as well as investors’ view of the oil and gas industry overall. We may not be able to access the capital markets in the future on terms favorable to us, or at all. Our continued access to capital markets is dependent on corporate performance and investor perception of future performance (both corporately and for the oil and gas sector in general).

We are required to assess our foreign private issuer (“FPI”) status under U.S. securities laws on an annual basis. If we lose our FPI status, we may have restricted access to capital markets for a period of time until the required approvals are in place from the SEC.

34 ENERPLUS 2022 FINANCIAL SUMMARY

Access to Transportation and Processing Capacity

Market access for crude oil, natural gas liquids and natural gas production in the U.S. and Canada is dependent on our ability, and the ability of our buyers as applicable, to obtain transportation capacity on third party pipelines and rail as well as access to processing facilities. As production increases in the regions where we operate, it is possible production may exceed the existing capacity of the gathering, pipeline, processing or rail infrastructure. While third party pipelines, processors and independent rail operators generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of capacity. There are occasionally operational reasons for curtailing transportation and processing capacity. Accordingly, there can be periods where transportation and processing capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. Our assets are concentrated in specific regions where government or other third parties could limit or ban the shipping of commodities by truck, pipeline or rail. Special interest groups and/or social instability could also prevent access to leased land or continue their opposition to infrastructure development, at either the regulatory or judicial level, including the ongoing matters with respect to DAPL, resulting in operational delays, or even the cancellation of construction of the required infrastructure, or the shutdown of already operating infrastructure projects, further impeding our ability to operate, produce and market our products. Additionally, the transportation of crude oil by rail has been under closer scrutiny by government regulatory agencies the U.S. over the past few years. As a result, transporting crude oil by rail may carry a higher cost versus traditional pipeline infrastructure or other means of transporting production.

We monitor this risk for both the short and longer term through dialogue and review with the third-party pipelines and other market participants. Where available and commercially appropriate, given the production profile and commodity, we attempt to mitigate transportation and processing risk by contracting for firm pipeline or processing capacity or using other means of transportation, including trucking or selling to third parties that have access to pipeline or rail capacity.

Risk of Curtailed or Shut-in Production

Should we be required to curtail or shut-in production as a result of environmental regulation, government regulation, third-party operational practices, or low commodity prices, it could result in a reduction to cash flow and production levels and may result in additional operating and capital costs for the well to achieve prior production levels. In addition, curtailments or shut-ins may cause damage to the reservoir and may prevent us from achieving production and operating levels that were in place prior to the curtailment or shutting-in of the reservoir. Combined with the ongoing volatility in commodity prices, any shortage in pipeline infrastructure in producing regions where we operate may result in discounted prices and an ongoing risk of price-related production curtailments.

Production Replacement Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new land, reserves and/or resources and developing existing reserves and resources. Acquisitions of oil and gas assets will depend on our assessment of value at the time of acquisition and ability to secure the acquisitions generally through a competitive bid process.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions and our annual capital development budget are approved by the Board of Directors and where appropriate, independent reserve engineer evaluations are obtained.

Oil and Gas Reserves and Resources Risk

The value of our company is based on, among other things, the underlying value of our oil and gas reserves and resources. Geological and operational risks along with product price forecasts can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower crude oil, natural gas liquids, and natural gas prices along with lower development capital spending associated with certain projects may increase the risk of write-downs for our oil and gas property investments. Changes in reporting methodology as well as regulatory practices can result in reserves or resources write-downs.

Each year, independent reserves engineers evaluate the majority of our proved and probable reserves as well as evaluate or audit the resources attributable to a significant portion of our undeveloped land. All reserves information, including our U.S. reserves, has been prepared in accordance with Canadian NI 51-101 Standards. For U.S. GAAP accounting purposes, our proved reserves are estimated to be technically the same as our proved reserves prepared under Canadian NI 51-101 Standards and have been adjusted for the effects of SEC constant prices. Independent reserves evaluations have been conducted on 100% of the total proved plus probable net present value (discounted at 10% and using Canadian NI 51-101 Standards) of our reserves at December 31, 2022. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 100% of the reserves associated with our U.S. tight oil assets. Netherland, Sewell & Associates, Inc. (“NSAI”) evaluated 100% of our U.S. Marcellus shale gas assets.

ENERPLUS 2022 FINANCIAL SUMMARY 35

The evaluation of best estimate development pending contingent resources associated with our North Dakota assets was conducted by McDaniel. NSAI evaluated our Marcellus shale gas best estimate development pending contingent resources. The RS&SR Committee of the Board of Directors and the Board of Directors has reviewed and approved the reserves and resources reports of the independent evaluators.

Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets

Under U.S. GAAP, the net capitalized cost of crude oil and natural gas properties, net of deferred income taxes, is limited to the present value of after-tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer’s reporting date. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

Under U.S. GAAP, the net deferred tax asset is limited to the estimate of future taxable income resulting from existing properties. We estimate future taxable income based on before-tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income, however these amounts can be reversed in future periods if future taxable income increases.

No impairment was recorded in 2022. We recorded an impairment of $3.4 million related to our Canadian assets in 2021. In 2020, we recorded an impairment of $751.7 million (Canadian cost centre: $100.9 million, U.S. cost centre $650.8 million) on our crude oil and natural gas assets. We continue to record a valuation allowance against our capital related deferred tax assets, however, no valuation allowance was recorded in 2022 or 2021 against our income related deferred tax assets. In 2020, we reversed our valuation allowance of $11.5 million recorded in 2019 against a portion of our Canadian deferred income tax asset, as projected future taxable income in Canada was sufficient to recognize these assets. No valuation allowance was recorded against our U.S. deferred income tax asset in 2020. There is a risk of impairment on our oil and gas properties, and deferred tax asset if commodity prices weaken, costs increase, or if there is a downward revision to reserves. Please refer to the “Impairments” and “Income Taxes” sections of the MD&A and Notes 6 and 14 of the Financial Statements for further details.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may change in a manner that adversely affects us or our security holders. Canadian, U.S. and foreign tax authorities may interpret applicable tax laws, tax treaties or administrative positions differently than we do or may disagree with how we calculate our income for tax purposes in a manner which is detrimental to us and our security holders.

We monitor developments with respect to pending legal changes and work with the industry and professional groups to ensure that our concerns with any changes are made known to various government agencies. We obtain confirmation from independent legal counsel and advisors with respect to the interpretation and reporting of material transactions.

Counterparty and Joint Venture Credit Exposure

We are subject to the risk that the counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements as a result of liquidity requirements or insolvency. Low crude oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure of our counterparties to perform their financial or operational obligations may adversely affect our operations and financial position. In addition to the usual delays in payment by purchasers of crude oil and natural gas, payments may also be delayed by, among other things: (i) capital or liquidity constraints experienced by our counterparties, including restrictions imposed by lenders; (ii) accounting delays or adjustments for prior periods; (iii) delays in the sale or delivery of products or delays in the connection of wells to a gathering system; (iv) adverse weather conditions, such as freezing temperatures, storms, flooding and premature thawing; (v) blow-outs or other accidents; or (vi) recovery by the operator of expenses incurred in the operation of the properties or the establishment by the operator of reserves for these expenses. Any of these delays could reduce the amount of our cash flow and the payment of cash dividends to our shareholders in a given period and expose us to additional third-party credit risks.

A credit review process is in place to assess and monitor our counterparties’ credit worthiness on a regular basis. This includes reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we attempt to obtain financial assurances such as letters of credit, parental guarantees, or third-party insurance to mitigate our counterparty risk. In addition, we monitor our receivables against a watch list of publicly traded companies that have high debt-to-cash flow ratios or fully drawn bank facilities and, where possible, take our production in kind rather than relying on third party operators. In certain instances, we may be able to aggregate all amounts owing to each other and settle with a single net amount.

See the “Liquidity and Capital Resources” section for further information.

36 ENERPLUS 2022 FINANCIAL SUMMARY

Risk of Exceeding Debt Covenants

Declines or continued volatility in crude oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead us to increase amounts drawn under our Bank Credit Facilities in order to carry out our operations and fulfill our obligations. Significant reductions to cash flow, significant increases in drawn amounts under the Bank Credit Facilities, or significant reductions to proved reserves may result in us breaching our debt covenants under the Bank Credit Facilities and senior notes. If a breach occurs, there is a risk that we may not be able to negotiate covenant relief with one or more of our lenders under the Bank Credit Facilities or senior notes. Failure to comply with debt covenants, or negotiate relief, may result in our indebtedness under the Bank Credit Facilities or senior notes becoming immediately due and payable, which may have a material adverse effect on our operations and financial condition.

Risk of Insufficient Liquidity

Although we believe that our existing Bank Credit Facilities and senior notes are sufficient, there can be no assurance that the current amount will continue to be available, or will be adequate for our financial obligations, or that additional funds can be obtained as required or on terms which are economically advantageous to Enerplus. The amounts available under the Bank Credit Facilities and senior notes may not be sufficient for future operations, or we may not be able to renew our Bank Credit Facilities or obtain additional financing on attractive economic terms, if at all. The Bank Credit Facilities are generally extendable each year with a bullet payment required at the end of the term if the facility is not renewed. The $365 million Bank Credit Facility currently matures on October 31, 2025; $50 million and $850 million of the $900 million Bank Credit Facility matures on October 31, 2025 and October 31, 2026, respectively. There can be no assurance that such a renewal will be available on favourable terms or that all the current lenders under the facility will participate or renew at their current commitment levels. If this occurs, we may need to obtain alternate financing. Any failure of a member of the lending syndicate to fund its obligations under the Bank Credit Facilities or to renew its commitment in respect of such Bank Credit Facilities, or failure by Enerplus to obtain replacement financing or financing on favourable terms, may have a material adverse effect on our business and operations. In addition, dividends to shareholders may be eliminated, as repayment of debt under the Bank Credit Facilities and senior notes has priority over dividend payments to our shareholders.

Title Defects or Litigation

Unforeseen title defects or litigation may result in a loss of entitlement to production, reserves and resources.

Although we conduct title reviews prior to the purchase of assets these reviews do not guarantee that an unforeseen defect in the chain of title will not arise. We maintain good working relationships with our industry partners; however, disputes may arise from time to time with respect to ownership of rights of certain properties or resources.

Foreign Currency Exposure

Beginning with the year ended December 31, 2021, we elected to change our reporting currency from Canadian dollars to U.S. dollars since the majority of our crude oil and natural gas properties are located in the U.S. Transactions denominated in foreign currencies are translated to the functional currency of the entity (U.S. dollars for all of our entities) using the exchange rate prevailing at the date of the transaction and, in the case of Canadian entities, then translated to U.S. dollars for reporting purposes. As a result, transactions in Canadian entities are affected by the exchange rate between the U.S. and Canadian dollar, including U.S. dollar denominated debt held in our Canadian parent, Canadian denominated receipts and payments and Canadian dollar dividend payments.

Enerplus is exposed to foreign exchange risk as it relates to Canadian and U.S. dollar. Subsequent to December 31, 2022, on January 1, 2023, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a change in functional currency to U.S. dollars, consistent with the functional currency of the U.S. subsidiary. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2022, we did not have any foreign exchange derivatives outstanding.

We continue to monitor fluctuations in foreign exchange and the impact on our operations.

Interest Rate Exposure

Movements in interest rates and credit markets may affect our borrowing costs and value of investments such as our shares as well as other equity investments.

Enerplus’ senior notes bear interest at fixed rates while the Bank Credit Facilities bear interest at floating rates. At December 31, 2022, approximately 78% of Enerplus’ debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43% and 57% fixed), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2%, 1.9%). At December 31, 2022 and 2021, Enerplus did not have any interest rate derivatives outstanding.

ENERPLUS 2022 FINANCIAL SUMMARY 37

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all of Enerplus’ commodity contracts listed in Note 16 to the Financial Statements and are based on 2023 guidance production and price levels of: WTI - $80.00/bbl, NYMEX - $3.50/Mcf and a CDN/US exchange rate of 0.75. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.


	Estimated Effect on 2023
Sensitivity Table	Adjusted Funds Flow per Share⁽¹⁾
Increase of $5.00 per barrel in the price of WTI crude oil	$	0.29
Decrease of $5.00 per barrel in the price of WTI crude oil	$	(0.28)
Increase of $0.50 per Mcf in the price of NYMEX natural gas	$	0.10
Decrease of $0.50 per Mcf in the price of NYMEX natural gas	$	(0.10)
Change of 1,000 BOE/day in production	$	0.06

(1)	Calculated using 216.5 million shares outstanding at February 22, 2023.

2023 GUIDANCE⁽¹⁾


Summary of 2023 Annual Expectations		Target
Capital spending ($ millions)		$500 - $550
Average annual production (BOE/day)		93,000 - 98,000
Average annual crude oil and natural gas liquids production (bbls/day)		57,000 - 61,000
Average production tax rate (% of gross sales, before transportation)		7%
Operating expenses (per BOE)		$10.75 - $11.75
Transportation costs (per BOE)		$4.35
Cash G&A expenses (per BOE)		$1.35
Current tax expense (% of adjusted funds flow before tax)		5% - 6%


Differential/Basis Outlook⁽²⁾		Target
Average U.S. Bakken crude oil differential (compared to WTI crude oil)		$0.75/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)		($0.75)/Mcf

(1)	This constitutes forward-looking information. Refer to “Forward-Looking Information and Statements” section in this MD&A.

(2)	Excludes transportation costs.

38 ENERPLUS 2022 FINANCIAL SUMMARY

NON-GAAP AND OTHER FINANCIAL MEASURES

Non-GAAP Financial Measures

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

These non-GAAP financial measures and non-GAAP ratios do not have standardized meanings or definitions as prescribed by U.S. GAAP and may not be comparable with the calculation of similar financial measures by other entities. For each measure, we have indicated the composition of the measure, identified the GAAP equivalency to the extent one exists, provided comparative detail where appropriate, indicated the reconciliation of the measure to the mostly directly comparable GAAP financial measure and provided details on the usefulness of the measure for the reader. These non-GAAP financial measures and non-GAAP ratios should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP.

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


	Year ended December 31,
($ millions)		2022		2021		2020
Net income/(loss)		$	914.3	$	234.4	$	(693.4)
Unrealized derivative instrument (gain)/loss			(150.5)		109.5		18.1
Gain on divestment of assets			(151.9)		—		—
Unrealized foreign exchange (gain)/loss			11.2		(8.1)		1.4
Other expense related to investing activities			13.1		—		—
Asset impairment			—		3.4		751.7
Tax effect on above items			64.0		(24.9)		(201.0)
Income tax rate adjustment on deferred taxes			8.8		6.0		—
Other income related to investing activities			(1.9)		(4.6)		—
Goodwill impairment			—		—		149.2
Valuation allowance on deferred taxes			—		—		(11.5)
Adjusted net income/(loss)		$	707.1	$	315.7	$	14.5

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


	Year ended December 31,
($ millions)		2022		2021		2020
Cash flow from/(used in) operating activities		$	1,173.4	$	604.8	$	335.9
Asset retirement obligation settlements			17.4		13.0		13.3
Changes in non-cash operating working capital			39.5		94.6		(83.7)
Adjusted funds flow		$	1,230.3	$	712.4	$	265.5
Capital spending			(432.0)		(302.3)		(217.2)
Free cash flow		$	798.3	$	410.1	$	48.3

ENERPLUS 2022 FINANCIAL SUMMARY 39

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


	Year ended December 31,
($ millions)		2022		2021		2020
Crude oil and natural gas sales		$	2,353.4	$	1,482.6	$	553.7
Less:
Operating expenses			(365.7)		(292.4)		(197.1)
Transportation expenses			(154.7)		(128.3)		(98.7)
Production taxes			(167.0)		(102.0)		(37.4)
Netback before impact of commodity derivative contracts		$	1,666.0	$	959.9	$	220.5
Net realized gain/(loss) on derivative instruments			(347.2)		(163.0)		92.9
Netback after impact of commodity derivative contracts		$	1,318.8	$	796.9	$	313.4

Other Financial Measures

CAPITAL MANAGEMENT MEASURES

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

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

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

“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.

SUPPLEMENTARY FINANCIAL MEASURES

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:

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

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

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

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

40 ENERPLUS 2022 FINANCIAL SUMMARY

INTERNAL CONTROLS AND PROCEDURES

Internal Controls over Financial Reporting

We maintain internal controls over financial reporting that are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rule 13a – 15(f) and 15d – 15(f) under the U.S. Securities Exchange Act of 1934, as amended (the Exchange Act) and under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (NI 51-109). Management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Enerplus Corporation, have conducted an evaluation of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013). Based on management’s assessment as of December 31, 2022, management has concluded that our internal controls over financial reporting are effective.

The effectiveness of internal controls over financial reporting as of December 31, 2022 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included with the annual financial statements.

Due to inherent limitations, internal controls over financial reporting are not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal

control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

Changes in Internal Controls over Financial Reporting

There were no changes in our internal control over financial reporting in 2022 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our interim and annual filings is reviewed, recognized and disclosed accurately and in the appropriate time period. Management, including the CEO and CFO, carried out an evaluation, as of December 31, 2022, of the effectiveness of the design and operation of disclosure controls and procedures of Enerplus, as defined in Rule 13a – 15(e) and 15d – 15(e) under the Exchange Act and NI 52-109. Based on that evaluation, the CEO and CFO have concluded that the design and operation of disclosure controls and procedures at Enerplus were effective to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act or Canadian securities legislation is recorded, processed, summarized and reported within the time periods specified in the rules and forms therein.

It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that these disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

ADDITIONAL INFORMATION

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

ENERPLUS 2022 FINANCIAL SUMMARY 41

PRESENTATION OF RESERVES INFORMATION

All of Enerplus’ reserves have been evaluated in accordance with Canadian reserve evaluation standards under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“Canadian NI 51-101 Standards”). Independent reserves evaluations have been conducted on properties comprising 100% of the net present value (discounted at 10%, before tax, using January 1, 2023 forecast prices and costs) of Enerplus’ total proved plus probable reserves. McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated all of Enerplus’ proved plus probable reserves associated with the Enerplus’ properties located in North Dakota and Colorado. NSAI, independent petroleum consultants based in Dallas, Texas, has evaluated all of Enerplus’ reserves associated with Enerplus’ properties in Pennsylvania in accordance with Canadian NI 51-101 Standards. For consistency in the Enerplus’ reserves reporting, NSAI also used the average commodity price forecasts and inflation rates of McDaniel, GLJ Ltd. and Sproule Associates Limited, independent petroleum consultants, as of January 1, 2023 to prepare its report.

Enerplus has also presented certain reserves information effective December 31, 2022 in accordance with the provisions of the Financial Accounting Standards Board’s ASC Topic 932 Extractive Activities – Oil and Gas, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the SEC, but does not necessarily include all of the disclosure required by the SEC disclosure standards set forth in Subpart 1200 of Regulation S-K (the "U.S. Standards"). Concurrent to the evaluation of Enerplus’ Canadian NI 51-101 Standards reserves, McDaniel and NSAI prepared and reviewed estimates of Enerplus’ reserves under the U.S. Standards. The practice of preparing production and reserves data under Canadian NI 51-101 Standards differs from the U.S. Standards. The primary differences between the two reporting requirements include:

●

the Canadian NI 51-101 Standards require disclosure of proved and probable reserves, while the U.S. Standards require disclosure of only proved reserves;

●

the Canadian NI 51-101 Standards require the use of forecast prices in the estimation of reserves, while the U.S. Standards require the use of 12-month average trailing historical prices, which are held constant;

●

the Canadian NI 51-101 Standards require disclosure of reserves on a gross (before royalties) and net (after royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;

●

the Canadian NI 51-101 Standards require disclosure of production on a gross (before royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;

●

the Canadian NI 51-101 Standards require that reserves and other data be reported on a more granular product type basis than required by the U.S. Standards; and

●

the Canadian NI 51-101 Standards require that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves.

F&D costs presented in this MD&A 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 U.S. dollars per net of gross BOE as specified.

Complete disclosure of our oil and gas reserves and other oil and gas information presented in accordance with Canadian NI 51-101 Standards, as well as supplemental information presented in accordance with U.S. Standards, is contained within our AIF, 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.

42 ENERPLUS 2022 FINANCIAL SUMMARY

FORWARD-LOOKING INFORMATION AND STATEMENTS

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: expected 2023 average production volumes, timing thereof and the anticipated production mix; expected increase in gas processing and higher well service activity; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; adjusted funds flow sensitivity and the estimated effect on adjusted funds flow per share in 2023; oil and natural gas prices and differentials; expectations regarding market environment and our commodity risk management program in 2023 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 G&A, share-based compensation and financing expenses; operating, transportation and tax expenses; expected free cash flow generation and use thereof, including to fund share repurchases and dividends; the anticipated percentage of free cash flow planned to be returned to shareholders; the anticipated renewal of our NCIB and the timing thereof; capital spending levels in 2023 and impact thereof on our production levels and land holdings; potential future asset impairments, as well as relevant factors that may affect such impairments; the amount and timing of our future abandonment and reclamation costs and asset retirement obligations and the source of funds necessary in order to pay such obligations; our ESG initiatives, including Scope 1 and Scope 2 GHG emissions and methane emissions intensity and health and safety targets; future environmental expenses; our future royalty and production and cash taxes; deferred income taxes, our tax pools and the time at which we may pay cash taxes; future debt and working capital levels, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with or renegotiate debt covenants under our Bank Credit Facilities and outstanding senior notes; our future acquisitions and dispositions; and the amount of future cash dividends that we may pay to our shareholders and the source of funds necessary in order to pay such dividends.

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: the ability to fund our return of capital plans, including both dividends at the current level and the share repurchase program, from free cash flow as expected; that our common share trading price will be at levels, and that there will be no other alternatives, that, in each case, make share repurchases an appropriate and best strategic use of our free cash flow; that we will conduct our operations and achieve results of operations as anticipated, including 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 and expectations regarding the duration and overall impact of the continued conflict in Ukraine and the COVID-19 pandemic 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 Facilities to fund our working capital deficiency; our ability to comply with our debt covenants; our ability to meet the targets associated with Bank Credit Facilities; the availability of third party services; factors used to assess the realizability of our deferred income tax assets; the extent of our liabilities; and the availability of technology and process to achieve environmental targets. In addition, our 2023 guidance contained in this MD&A is based on the following: a WTI price of $80.00/bbl, a NYMEX price of $3.50/Mcf, a Bakken crude oil price differential of $0.75/bbl above WTI, a Marcellus natural gas price differential of $0.75/Mcf below NYMEX and a CDN/US exchange rate of 0.75. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The term material, in reference to the ESG material focus areas, is not used for, does not have, and is not intended to have, the same meaning as such term is assigned under applicable securities laws, including, but not limited to, with respect to financial materiality, materiality to investors or creditors, enterprise value, or other indications of financial impact, and is used solely to reflect the Company’s identification of those ESG issues that the Company has determined within its judgement present significant ESG risks or opportunities to its operations.

ENERPLUS 2022 FINANCIAL SUMMARY 43

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 conditions, including from COVID-19 or similar events, inflation and/or Ukraine/Russia conflict and heightened geopolitical risk; 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 and including as a result of ongoing disruptions to global supply chains; volatility in our common share trading price and free cash flow that could impact our planned share repurchases and dividend levels; unanticipated operating results, results from our capital spending activities or production declines; 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 and increased capital and operating costs resulting therefrom; inability to comply with applicable environmental government regulations or regulatory approvals and resulting compliance and enforcement actions; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our Bank Credit Facilities and 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 Unites 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 AIF and Form 40-F as at December 31, 2022).

The purpose of our adjusted funds flow sensitivity is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, 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. Any forward-looking information contained herein is expressly qualified by this cautionary statement.

44 ENERPLUS 2022 FINANCIAL SUMMARY