Enerplus 6K Current report | ERF 5 Nov 21

STATEMENTS

Exhibit 99.2

Condensed Consolidated Balance Sheets


(CDN$ thousands) unaudited	Note	September 30, 2021		December 31, 2020
Assets
Current Assets
Cash and cash equivalents		$	54,114	$	114,455
Accounts receivable	5		298,619		106,376
Other current assets			8,966		7,137
Derivative financial assets	17		—		3,550
			361,699		231,518
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)	6		1,702,251		575,559
Other capital assets, net	6		24,944		19,524
Property, plant and equipment			1,727,195		595,083
Right-of-use assets	11		35,094		32,853
Deferred income tax asset	15		567,622		607,001
Total Assets		$	2,691,610	$	1,466,455

Liabilities
Current liabilities
Accounts payable	8	$	415,970	$	251,822
Dividends payable			—		2,225
Current portion of long-term debt	9		127,561		103,836
Derivative financial liabilities	17		241,658		19,261
Current portion of lease liabilities	11		13,489		13,391
			798,678		390,535

Long-term debt	9		974,280		386,586
Asset retirement obligation	10		162,099		130,208
Derivative financial liabilities	17		42,813		—
Lease liabilities	11		25,228		23,446
			1,204,420		540,240
Total Liabilities			2,003,098		930,775

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: September 30, 2021 – 255 million shares December 31, 2020 – 223 million shares	16		3,215,224		3,096,969
Paid-in capital			40,513		50,604
Accumulated deficit			(2,885,099)		(2,932,017)
Accumulated other comprehensive income/(loss)			317,874		320,124
			688,512		535,680
Total Liabilities & Shareholders' Equity		$	2,691,610	$	1,466,455

Commitments	19
Subsequent Events	16, 20

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

ENERPLUS 2021 Q3 REPORT 1

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


		Three months ended				Nine months ended
		September 30,				September 30,
(CDN$ thousands, except per share amounts) unaudited	Note	2021		2020		2021		2020
Revenues
Crude oil and natural gas sales, net of royalties	12	$	531,220	$	191,944	$	1,228,643	$	542,140
Commodity derivative instruments gain/(loss)	17		(78,947)		894		(346,757)		121,340
			452,273		192,838		881,886		663,480
Expenses
Operating			112,309		65,129		265,290		198,502
Transportation			41,008		32,209		110,019		101,544
Production taxes			38,293		13,610		86,247		36,741
General and administrative	13		15,635		8,392		44,381		41,071
Depletion, depreciation and accretion			102,380		62,147		242,748		237,224
Asset impairment	7		—		256,809		4,300		683,619
Goodwill impairment	7		—		—		—		202,767
Interest			10,451		6,339		26,801		22,301
Foreign exchange (gain)/loss	14		(12,297)		946		(5,311)		(3,198)
Transaction costs and other expense/(income)	4,10,18		(5,898)		123		(2,092)		6,195
			301,881		445,704		772,383		1,526,766
Income/(Loss) before taxes			150,392		(252,866)		109,503		(863,286)
Current income tax expense/(recovery)	15		(1,172)		(130)		3,003		(14,525)
Deferred income tax expense/(recovery)	15		39,555		(139,983)		39,458		(129,561)
Net Income/(Loss)		$	112,009	$	(112,753)	$	67,042	$	(719,200)

Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation			21,585		(21,559)		(5,627)		52,931
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax	17		(19,847)		9,905		3,377		(20,691)
Total Comprehensive Income/(Loss)		$	113,747	$	(124,407)	$	64,792	$	(686,960)

Net income/(Loss) per share
Basic	16	$	0.44	$	(0.51)	$	0.27	$	(3.23)
Diluted	16	$	0.43	$	(0.51)	$	0.26	$	(3.23)

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

2 ENERPLUS 2021 Q3 REPORT

Condensed Consolidated Statements of Changes in Shareholders’ Equity


		Three months ended				Nine months ended
		September 30,				September 30,
(CDN$ thousands) unaudited	2021		2020		2021		2020
Share Capital
Balance, beginning of period	$	3,236,117	$	3,096,969	$	3,096,969	$	3,088,094
Issue of shares (net of issue costs, less tax)		—		—		127,248		—
Purchase of common shares under Normal Course Issuer Bid		(20,893)		—		(20,893)		(4,731)
Share-based compensation – treasury settled		—		—		11,900		13,824
Cancellation of predecessor shares		—		—		—		(218)
Balance, end of period	$	3,215,224	$	3,096,969	$	3,215,224	$	3,096,969

Paid-in Capital
Balance, beginning of period	$	36,269	$	48,758	$	50,604	$	59,490
Share-based compensation – cash settled (tax withholding)		—		—		(4,491)		(7,232)
Share-based compensation – treasury settled		—		—		(11,900)		(13,824)
Share-based compensation – non-cash		4,244		(3,395)		6,300		6,929
Balance, end of period	$	40,513	$	45,363	$	40,513	$	45,363

Accumulated Deficit
Balance, beginning of period	$	(2,995,389)	$	(2,601,744)	$	(2,932,017)	$	(1,984,365)
Purchase of common shares under Normal Course Issuer Bid		8,038		—		8,038		2,195
Cancellation of predecessor shares		—		—		—		218
Net income/(loss)		112,009		(112,753)		67,042		(719,200)
Dividends declared⁽¹⁾		(9,757)		(6,676)		(28,162)		(20,021)
Balance, end of period	$	(2,885,099)	$	(2,721,173)	$	(2,885,099)	$	(2,721,173)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of period	$	316,136	$	352,233	$	320,124	$	308,339
Unrealized gain/(loss) on foreign currency translation		21,585		(21,559)		(5,627)		52,931
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax		(19,847)		9,905		3,377		(20,691)
Balance, end of period	$	317,874	$	340,579	$	317,874	$	340,579
Total Shareholders’ Equity	$	688,512	$	761,738	$	688,512	$	761,738

(1)	For the three and nine months ended September 30, 2021, dividends declared were $0.038 per share and $0.112 per share, respectively (2020 – $0.03 per share and $0.09 per share, respectively).

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

ENERPLUS 2021 Q3 REPORT 3

Condensed Consolidated Statements of Cash Flows


		Three months ended				Nine months ended
		September 30,				September 30,
(CDN$ thousands) unaudited	Note	2021		2020		2021		2020
Operating Activities
Net income/(loss)		$	112,009	$	(112,753)	$	67,042	$	(719,200)
Non-cash items add/(deduct):
Depletion, depreciation and accretion			102,380		62,147		242,748		237,224
Asset impairment	7		—		256,809		4,300		683,619
Goodwill impairment	7		—		—		—		202,767
Changes in fair value of derivative instruments	17		16,174		19,214		226,146		(13,285)
Deferred income tax expense/(recovery)	15		39,555		(139,983)		39,458		(129,561)
Foreign exchange (gain)/loss on debt and working capital	14		(12,680)		487		(6,822)		(890)
Share-based compensation and general and administrative	13,16		4,128		(2,898)		5,118		8,285
Other expense/(income)	10		(264)		—		(2,617)		—
Amortization of debt issuance costs	9		534		—		919		—
Translation of U.S. dollar cash held in Canada	14		(368)		42		(2,389)		(2,670)
Other income reclassified to Investing Activities	18		(5,720)		—		(5,720)		—
Asset retirement obligation settlements	10		(2,142)		(1,905)		(10,581)		(13,032)
Changes in non-cash operating working capital	18		(26,964)		55,827		(156,819)		97,029
Cash flow from/(used in) operating activities			226,642		136,987		400,783		350,286

Financing Activities
Bank term loan	9		—		—		501,286		—
Bank credit facility	9		(131,706)		(1,364)		201,910		—
Repayment of senior notes	9		—		—		(99,348)		(114,010)
Proceeds from the issuance of shares	16		—		—		125,746		—
Purchase of common shares under Normal Course Issuer Bid	16		(12,855)		—		(12,855)		(2,536)
Share-based compensation – cash settled (tax withholding)	16		—		—		(4,491)		(7,232)
Dividends	16,18		(9,757)		(6,676)		(30,384)		(20,013)
Cash flow from/(used in) financing activities			(154,318)		(8,040)		681,864		(143,791)

Investing Activities
Capital and office expenditures	18		(96,073)		(47,228)		(240,257)		(280,681)
Bruin acquisition	4		—		—		(531,134)		—
Dunn County acquisition	4		(230)		—		(374,843)		—
Property and land acquisitions			(5,557)		(2,388)		(10,583)		(8,060)
Property divestments			(271)		583		4,707		6,098
Other expense/(income)	18		5,720		—		5,720		—
Cash flow from/(used in) investing activities			(96,411)		(49,033)		(1,146,390)		(282,643)
Effect of exchange rate changes on cash & cash equivalents			2,923		(1,544)		3,402		9,046
Change in cash and cash equivalents			(21,164)		78,370		(60,341)		(67,102)
Cash and cash equivalents, beginning of period			75,278		6,177		114,455		151,649
Cash and cash equivalents, end of period		$	54,114	$	84,547	$	54,114	$	84,547

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

4 ENERPLUS 2021 Q3 REPORT

NOTES

Notes to Condensed Consolidated Financial Statements

(unaudited)

1) REPORTING ENTITY

These interim Condensed Consolidated Financial Statements (“interim Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (the “Company” or “Enerplus”) including its Canadian and United States (“U.S.”) subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

2) BASIS OF PREPARATION

Enerplus’ interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in the United States of America (“U.S. GAAP”) for the three and nine months ended September 30, 2021 and the 2020 comparative periods. Certain prior period amounts have been reclassified to conform with current period presentation. Certain information and notes normally included with the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with Enerplus’ annual audited Consolidated Financial Statements as of December 31, 2020.

These unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of the Company as at and for the periods presented.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: crude oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), fair value of acquired property, plant and equipment, impairment of property, plant and equipment, asset retirement obligation, income taxes, ability to realize deferred income tax assets and the fair value of derivative instruments. 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 inputs and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. When estimating the present value of future cash flows, the discount rate is not directly adjusted for the potential impacts, if any, due to climate change factors. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions.

3) ACCOUNTING POLICY CHANGES

Recently adopted accounting standards

Government Assistance

In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus has applied for and benefited from these programs in 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as other income in the Condensed Consolidated Statements of Income/(Loss).

ENERPLUS 2021 Q3 REPORT 5

4) ACQUISITIONS

a)	Bruin E&P HoldCo, LLC Acquisition

On January 25, 2021, Enerplus Resources (USA) Corporation, an indirect wholly-owned subsidiary of Enerplus entered into a purchase agreement to acquire all of the equity interests of Bruin E&P HoldCo, LLC (“Bruin”) for total cash consideration of US$465 million, subject to certain purchase price adjustments. Bruin was a private company that held oil and gas interests in certain properties located in the Williston Basin, North Dakota. The effective date of the acquisition was January 1, 2021 and the acquisition was completed on March 10, 2021.

The acquisition was funded through a new three-year US$400 million term loan provided by a syndicate of financial institutions as well as a portion of the proceeds raised through a bought deal offering of common shares of the Company, which was completed on February 3, 2021. A total of 33,062,500 common shares were issued at a price of $4.00 per common share for gross proceeds of approximately $132.3 million (net proceeds of $127.2 million).

The acquisition contributed $255.4 million to crude oil and natural gas revenues, net of royalties and $60.0 million to consolidated earnings before tax from the acquisition date to September 30, 2021. Transaction costs of nil and $6.2 million were incurred for the three and nine months ended September 30, 2021, respectively.

If the transaction had occurred on January 1, 2021, the combined entity’s unaudited pro-forma crude oil and natural gas revenues, net of royalties for the three and nine months ended September 30, 2021 would be $531.2 million and $1,299.9 million, respectively (2020 – $288.3 million and $738.9 million, respectively). For the three and nine months ended September 30, 2021 the combined entity would have net income of $112.0 million and $20.2 million, respectively (2020 – net losses of $97.8 million and $1,431.2 million, respectively).

The unaudited pro-forma information may not be indicative of the results that actually would have occurred if the events reflected therein had been in effect on the dates indicated or of the results that may be obtained in the future. No pro forma adjustments were made to reflect operating synergies that resulted from the transaction.

Purchase Price Consideration

The transaction was accounted for as an acquisition of a business. The purchase price is measured as the fair value of the assets transferred, equity instruments issued, and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The purchase price equation was determined following the closing date, during which time the value of the net assets and liabilities acquired was revised as indicated in the agreement and is reflected in the purchase price equation as follows:


($ thousands)	At March 10, 2021
Consideration
Purchase Price (US$465 million)	$	587,667
Purchase price adjustments		(56,533)
Total consideration	$	531,134

Fair value of identifiable assets and liabilities of Bruin
Other current assets		2,108
Property, plant and equipment		685,219
Right of use assets		2,391
Accounts payable		(31,920)
Asset retirement obligation		(27,759)
Derivative financial liabilities		(96,514)
Lease liabilities		(2,391)
Total identifiable net assets	$	531,134

6 ENERPLUS 2021 Q3 REPORT

b)	Dunn County Acquisition

On April 8, 2021, the Company announced it had entered into a purchase agreement to acquire assets in Dunn County, North Dakota from Hess Bakken Investments II, LLC for total cash consideration of approximately US$312 million, subject to customary purchase price adjustments. The acquisition was funded using the Company’s existing cash balance with the remaining portion funded through borrowing on its bank credit facility. The effective date of the acquisition was March 1, 2021 and the acquisition closed on April 30, 2021.

The acquisition was recorded as an asset acquisition as of the close date of April 30, 2021 with the results of operations reflected in these interim Consolidated Financial Statements thereafter. After purchase price adjustments, the purchase consideration including capitalized transaction costs was $376.9 million (US$306.8 million).

5) ACCOUNTS RECEIVABLE


($ thousands)	September 30, 2021		December 31, 2020
Accrued revenue	$	259,990	$	93,147
Accounts receivable – trade		43,529		16,808
Allowance for doubtful accounts		(4,900)		(3,579)
Total accounts receivable, net of allowance for doubtful accounts	$	298,619	$	106,376

6) PROPERTY, PLANT AND EQUIPMENT (“PP&E”)


			Accumulated Depletion,
As of September 30, 2021			Depreciation, and
($ thousands)		Cost	Impairment			Net Book Value
Crude oil and natural gas properties⁽¹⁾	$	16,572,168	$	(14,869,917)	$	1,702,251
Other capital assets		136,710		(111,766)		24,944
Total PP&E	$	16,708,878	$	(14,981,683)	$	1,727,195


			Accumulated Depletion,
As of December 31, 2020			Depreciation, and
($ thousands)		Cost	Impairment			Net Book Value
Crude oil and natural gas properties⁽¹⁾	$	15,227,076	$	(14,651,517)	$	575,559
Other capital assets		127,527		(108,003)		19,524
Total PP&E	$	15,354,603	$	(14,759,520)	$	595,083

(1)	All of the Company’s unproved properties are included in the full cost pool.

7) IMPAIRMENT

a)	Impairment of PP&E


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Crude oil and natural gas properties:
Canada cost centre	$	—	$	23,349	$	4,300	$	100,849
U.S. cost centre		—		233,460		—		582,770
Asset impairment	$	—	$	256,809	$	4,300	$	683,619

For the three and nine months ended September 30, 2021, Enerplus recorded asset impairments of nil and $4.3 million, respectively (2020 – $256.8 million and $683.6 million, respectively). During the first nine months of 2021, all asset impairments recorded related to Enerplus’ Canadian cost centre, whereas the asset impairments recorded in the first nine months of 2020 related to both Canadian and U.S. cost centres. The primary factors that affect future ceiling values include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, and production levels.

ENERPLUS 2021 Q3 REPORT 7

The following table outlines the twelve month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling tests from September 30, 2020 through September 30, 2021:


		WTI Crude Oil		Edm Light Crude		U.S. Henry Hub	Exchange Rate
Period		US$/bbl		CDN$/bbl		Gas US$/Mcf	US$/CDN$
Q3 2021	$	57.64	$	67.27	$	3.00	1.27
Q2 2021		49.72		58.31		2.47	1.28
Q1 2021		39.95		46.10		2.18	1.33
Q4 2020		39.54		45.56		2.00	1.34
Q3 2020		43.63		50.03		1.97	1.34

b)	Ceiling Test Exemption

Enerplus is required to calculate a full cost ceiling test at each reporting period, using constant prices as defined by the SEC under U.S. GAAP. These prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. At March 31, 2021, the ceiling test resulted in the net carrying cost of Enerplus’ crude oil and natural gas properties in its U.S. cost centre to exceed the ceiling test limitation by approximately US$265 million. This was primarily due to the difference in the ceiling value, using SEC constant prices for the Bruin assets acquired compared to the carrying value, which more closely represented fair market value based on forward prices. Enerplus requested and received a temporary exemption from the SEC to exclude the properties acquired from Bruin in the full cost ceiling test for the duration of 2021. At September 30, 2021, the ceiling test limitation exceeded the net carrying cost of the crude oil and natural gas properties, including the Bruin assets, in Enerplus’ U.S. cost centre.

c)	Impairment of Goodwill

At September 30, 2021, there was no goodwill remaining on the Company’s Condensed Consolidated Balance Sheets (December 31, 2020 – nil). During the three and nine months ended September 30, 2020, Enerplus recorded goodwill impairment of nil and $202.8 million respectively, relating to its U.S. reporting unit. This was due to lower commodity prices in 2020, which resulted in a reduction in the fair value of the U.S. reporting unit.

8) ACCOUNTS PAYABLE


($ thousands)	September 30, 2021		December 31, 2020
Accrued payables	$	131,826	$	107,254
Accounts payable – trade		284,144		144,568
Total accounts payable	$	415,970	$	251,822

9) DEBT


($ thousands)	September 30, 2021		December 31, 2020
Current:
Senior notes	$	127,561	$	103,836
Long-term:
Bank credit facility		212,305		—
Term loan		504,317		—
Senior notes		257,658		386,586
Total debt	$	1,101,841	$	490,422

Upon closing the Bruin acquisition on March 10, 2021, Enerplus entered into a three-year senior unsecured US$400 million term loan. The drawn fees align with those of Enerplus’ bank credit facility, which range between 125 and 315 basis points over banker’s acceptance or LIBOR rates. The term loan includes financial and other covenants consistent with Enerplus’ bank credit facility and ranks equally with the bank credit facility and outstanding senior notes. Debt issuance costs of $3.6 million have been netted against the term loan and are being amortized over the three-year term.

8 ENERPLUS 2021 Q3 REPORT

During 2021 Enerplus increased and extended its senior, unsecured, covenant-based bank credit facility to US$900 million from US$600 million with a maturity of October 31, 2025. Debt issuance costs of $2.2 million have been netted against the bank credit facility and are being amortized over the four and a half year term. As part of the extension, the Company transitioned the facility to a sustainability-linked credit facility incorporating 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 50% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2019 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, with progress to be measured on an annual basis over the life of the credit facility; 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.

For the three and nine months ended September 30, 2021, total amortization of debt issuance costs amounted to $0.5 million and $0.9 million, respectively.

The terms and rates of the Company’s outstanding senior notes are provided below:

Original

Remaining

CDN$ Carrying

Interest

Coupon

Principal

Value

Issue Date

Payment Dates

Principal Repayment

Rate

($ thousands)

September 3, 2014

March 3 and Sept 3

5 equal annual installments beginning September 3, 2022

3.79%

US$200,000

US$105,000

133,140

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

25,360

May 15, 2012

May 15 and Nov 15

3 equal annual installments beginning May 15, 2022

4.40%

US$355,000

US$178,800

226,719

Total carrying value

385,219

During the nine months ended September 30, 2021, Enerplus made its final US$22.0 million principal repayment on its 2009 senior notes and its second US$59.6 million principal repayment on its 2012 senior notes.

10) ASSET RETIREMENT OBLIGATION (“ARO”)


($ thousands)	September 30, 2021		December 31, 2020
Balance, beginning of year	$	130,208	$	138,049
Change in estimates		5,838		1,331
Property acquisitions and development activity		804		2,246
Bruin acquisition (Note 4a)		27,759		—
Dunn County acquisition (Note 4b)		7,291		—
Divestments		(2,010)		(1,030)
Settlements		(10,581)		(17,709)
Government assistance		(2,617)		—
Accretion expense		5,407		7,321
Balance, end of period	$	162,099	$	130,208

Enerplus has estimated the present value of its ARO to be $162.1 million at September 30, 2021 based on a total undiscounted uninflated liability of $438.6 million (December 31, 2020 – $130.2 million and $348.4 million, respectively).

In 2021, Enerplus benefited from provincial government assistance to support the clean-up 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 the three and nine months ended September 30, 2021, Enerplus benefited from $0.3 million and $2.6 million, respectively, in government assistance, which has been recorded as other income in the Condensed Consolidated Statements of Income/(Loss).

ENERPLUS 2021 Q3 REPORT 9

11) LEASES

The Company has entered into various lease contracts related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Condensed Consolidated Balance Sheets. Such items are charged to operating expenses or general and administrative expenses, as appropriate, in the Condensed Consolidated Statements of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with U.S. GAAP.


($ thousands)	September 30, 2021		December 31, 2020
Assets
Operating right-of-use assets	$	35,094	$	32,853

Liabilities
Current operating lease liabilities	$	13,489	$	13,391
Non-current operating lease liabilities		25,228		23,446
Total lease liabilities	$	38,717	$	36,837

Weighted average remaining lease term (years)
Operating leases		3.4		3.9

Weighted average discount rate
Operating leases		3.4%		4.2%

The Company’s lease contract expenditures/(income) for the three and nine months ended September 30, 2021 are as follows:


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Operating lease cost	$	3,565	$	3,649	$	10,584	$	12,964
Variable lease cost		215		708		578		1,215
Short-term lease cost		565		1,329		2,190		8,506
Sublease income		(348)		(345)		(936)		(889)
Total	$	3,997	$	5,341	$	12,416	$	21,796

Maturities of lease liabilities, all of which are classified as operating leases at September 30, 2021 are as follows:


($ thousands)	Operating Leases
2021	$	3,708
2022		14,134
2023		12,429
2024		7,051
2025		1,198
After 2025		2,686
Total lease payments	$	41,206
Less imputed interest		(2,489)
Total discounted lease payments	$	38,717
Current portion of lease liabilities	$	13,489
Non-current portion of lease liabilities	$	25,228

10 ENERPLUS 2021 Q3 REPORT

Supplemental information related to leases is as follows:


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	3,671	$	3,480	$	10,920	$	12,322
Right-of-use assets obtained/(terminated) in exchange for lease liabilities:
Operating leases	$	946	$	266	$	11,768	$	(2,683)

12) CRUDE OIL AND NATURAL GAS SALES, NET OF ROYALTIES


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Crude oil and natural gas sales	$	664,045	$	239,920	$	1,533,530	$	680,777
Royalties⁽¹⁾		(132,825)		(47,976)		(304,887)		(138,637)
Crude oil and natural gas sales, net of royalties	$	531,220	$	191,944	$	1,228,643	$	542,140

(1)	Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

Crude oil and natural gas revenue by country and by product for the three and nine months ended September 30, 2021 and 2020 are as follows:


Three months ended September 30, 2021		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	42,584	$	37,417	$	3,525	$	1,384	$	258
United States		488,636		388,159		72,382		28,084		11
Total	$	531,220	$	425,576	$	75,907	$	29,468	$	269


Three months ended September 30, 2020		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	27,686	$	23,248	$	3,349	$	791	$	298
United States		164,258		134,674		25,302		4,269		13
Total	$	191,944	$	157,922	$	28,651	$	5,060	$	311


Nine months ended September 30, 2021		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	113,647	$	99,406	$	9,652	$	3,867	$	722
United States		1,114,996		878,974		177,039		58,957		26
Total	$	1,228,643	$	978,380	$	186,691	$	62,824	$	748


Nine months ended September 30, 2020		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	67,804	$	54,957	$	8,858	$	2,450	$	1,539
United States		474,336		378,502		88,738		7,013		83
Total	$	542,140	$	433,459	$	97,596	$	9,463	$	1,622

(1)	Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

(2)	U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)	Includes third party processing income.

13) GENERAL AND ADMINISTRATIVE EXPENSE


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
General and administrative expense⁽¹⁾	$	10,669	$	11,527	$	34,424	$	33,093
Share-based compensation expense		4,966		(3,135)		9,957		7,978
General and administrative expense	$	15,635	$	8,392	$	44,381	$	41,071

(1)	Includes a non-cash lease credit of $116 and $341 for the three and nine months ended September 30, 2021 (2020 – credit of $117 and $170).

ENERPLUS 2021 Q3 REPORT 11

14) FOREIGN EXCHANGE


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Realized:
Foreign exchange (gain)/loss	$	751	$	417	$	3,900	$	362
Translation of U.S. dollar cash held in Canada (gain)/loss		(368)		42		(2,389)		(2,670)
Unrealized:
Translation of debt and working capital (gain)/loss		(12,680)		487		(6,822)		(890)
Foreign exchange (gain)/loss	$	(12,297)	$	946	$	(5,311)	$	(3,198)

15) INCOME TAXES


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Current tax
Canada	$	—	$	—	$	—	$	—
United States		(1,172)		(130)		3,003		(14,525)
Current tax expense/(recovery)		(1,172)		(130)		3,003		(14,525)
Deferred tax
Canada	$	(12,826)	$	(80,549)	$	(68,080)	$	18,303
United States		52,381		(59,434)		107,538		(147,864)
Deferred tax expense/(recovery)		39,555		(139,983)		39,458		(129,561)
Income tax expense/(recovery)	$	38,383	$	(140,113)	$	42,461	$	(144,086)

The difference between the expected income taxes based on the statutory income tax rate and the effective income taxes for the current and prior period is impacted by expected annual earnings, recognition or reversal of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, non-taxable portions of capital gains and losses, and share-based compensation.

The Company’s overall net deferred income tax asset was $567.6 million as at September 30, 2021 (December 31, 2020 – $607.0 million).

16) SHAREHOLDERS’ EQUITY

a) Share Capital


	Nine months ended			Year ended
Authorized unlimited number of common shares issued:	September 30, 2021			December 31, 2020
(thousands)	Shares		Amount	Shares		Amount
Balance, beginning of year	222,548	$	3,096,969	221,744	$	3,088,094

Issued/(Purchased) for cash:
Issue of shares (net of issue costs, less tax)	33,062		127,248	—		—
Purchase of common shares under Normal Course Issuer Bid	(1,658)		(20,893)	(340)		(4,731)

Non-cash:
Share-based compensation – treasury settled⁽¹⁾	1,140		11,900	1,160		13,824
Cancellation of predecessor shares	—		—	(16)		(218)
Balance, end of period	255,092	$	3,215,224	222,548	$	3,096,969

(1)	The amount of shares issued on long-term incentive settlement is net of employee withholding taxes.

Dividends declared to shareholders for the three and nine months ended September 30, 2021 were $9.8 million and $28.2 million, respectively (2020 – $6.7 million and $20.0 million, respectively). During the third quarter of 2021, the Company’s Board of Directors approved a 15% increase to the dividend to $0.038 per share, which began in September. This increase is in addition to the 10% increase approved in the second quarter of 2021. Subsequent to the quarter, the Board of Directors approved an 8% increase to the dividend to $0.041 per share beginning in December 2021.

During the nine months ended September 30, 2021, Enerplus issued 33,062,500 common shares at a price of $4.00 per common share for gross proceeds of $132.3 million (net $127.2 million, after $6.6 million in issue costs, net of $1.5 million in tax) pursuant to a bought deal prospectus offering under its base shelf prospectus.

12 ENERPLUS 2021 Q3 REPORT

On June 23, 2021, the Company filed a short form base shelf prospectus (the “Shelf Prospectus”) with securities regulatory authorities in each of the provinces and territories of Canada and a Registration Statement with the U.S. Securities Exchange Commission. The Shelf Prospectus allows Enerplus to offer and issue up to an aggregate amount of $2.0 billion common shares, preferred shares, warrants, subscription receipts and units by way of one or more prospectus supplements during the 25-month period that the Shelf Prospectus remains valid.

On August 12, 2021 Enerplus received approval from the Toronto Stock Exchange (“TSX”) to commence a Normal Course Issuer Bid (“NCIB”) to purchase up to 10% of the public float (within the meaning under TSX rules) during a 12-month period. As a result, 1,657,650 common shares were repurchased and cancelled under the NCIB at an average price of $7.75 per share, for total consideration of $12.9 million. Of the amount paid, $20.9 million was charged to share capital and $8.0 million was credited to accumulated deficit.

During the nine months ended September 30, 2020, the Company repurchased 340,434 common shares under the former NCIB at an average price of $7.44 per share, for total consideration of $2.5 million. Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit.

Subsequent to September 30, 2021 and up to and including November 3, 2021, the Company repurchased 434,700 common shares under the current NCIB at an average price of $11.52 per share, for total consideration of $5.0 million.

b) Share-based Compensation

The following table summarizes Enerplus’ share-based compensation expense, which is included in General and Administrative expense on the Condensed Consolidated Statements of Income/(Loss):


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Cash:
Long-term incentive plans (recovery)/expense	$	1,045	$	(738)	$	6,095	$	(2,299)
Non-Cash:
Long-term incentive plans expense		4,244		(2,781)		5,460		8,458
Equity swap (gain)/loss		(323)		384		(1,598)		1,819
Share-based compensation expense	$	4,966	$	(3,135)	$	9,957	$	7,978

i) Long-term Incentive (“LTI”) Plans

The following table summarizes the Performance Share Unit (“PSU”), Restricted Share Unit (“RSU”) and Director Deferred Share Unit (“DSU”) and Director RSU (“DRSU”) activity for the nine months ended September 30, 2021:


	Cash-settled LTI plans	Equity-settled LTI plans		Total
(thousands of units)	Director Plans	PSU⁽¹⁾	RSU
Balance, beginning of year	555	2,552	1,825	4,932
Granted	267	2,146	2,194	4,607
Vested	(13)	(728)	(890)	(1,631)
Forfeited	—	—	(71)	(71)
Balance, end of period	809	3,970	3,058	7,837

(1)	Based on underlying awards before any effect of the performance multiplier.

Cash-settled LTI Plans

For the three and nine months ended September 30, 2021, the Company recorded a cash share-based compensation expense of $1.0 million and $6.1 million, respectively (September 30, 2020 – recovery of $0.7 million and $2.3 million, respectively).

As of September 30, 2021, a liability of $8.2 million (December 31, 2020 – $2.2 million) with respect to the Director DSU and DRSU plans has been recorded to Accounts Payable on the Condensed Consolidated Balance Sheets.

ENERPLUS 2021 Q3 REPORT 13

Equity-settled LTI Plans

The following table summarizes the cumulative share-based compensation expense recognized to-date, which is recorded as Paid-in Capital on the Condensed Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.


At September 30, 2021 ($ thousands, except for years)	PSU⁽¹⁾		RSU		Total
Cumulative recognized share-based compensation expense	$	6,222	$	11,279	$	17,501
Unrecognized share-based compensation expense		8,356		7,455		15,811
Fair value	$	14,578	$	18,734	$	33,312
Weighted-average remaining contractual term (years)		1.5		1.2

(1)	Includes estimated performance multipliers.

The Company directly withholds shares on PSU and RSU settlements for tax-withholding purposes. For the three and nine months ended September 30, 2021, nil and $4.5 million (2020 – nil and $7.2 million) in cash withholding taxes were paid.

c) Basic and Diluted Net Income/(Loss) Per Share

Net income/(loss) per share has been determined as follows:


	Three months ended September 30,				Nine months ended September 30,
(thousands, except per share amounts)	2021		2020		2021		2020
Net income/(loss)	$	112,009	$	(112,753)	$	67,042	$	(719,200)

Weighted average shares outstanding – Basic		256,345		222,548		252,432		222,487
Dilutive impact of share-based compensation		4,486		—		4,468		—
Weighted average shares outstanding – Diluted		260,831		222,548		256,900		222,487
Net income/(loss) per share
Basic	$	0.44	$	(0.51)	$	0.27	$	(3.23)
Diluted	$	0.43	$	(0.51)	$	0.26	$	(3.23)

17) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At September 30, 2021, the carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximated their fair value due to the short-term nature of these instruments.

At September 30, 2021, the senior notes had a carrying value of $385.2 million and a fair value of $388.1 million (December 31, 2020 – $490.4 million and $494.1 million, respectively). The fair values of the bank credit facility and term loan approximate their carrying values as they bear interest at floating rates and the credit spread approximates current market rates.

The fair value of derivative contracts, senior notes, term loan, and credit facility are considered level 2 fair value measurements. There were no transfers between fair value hierarchy levels during the period.

14 ENERPLUS 2021 Q3 REPORT

b) Derivative Financial Instruments

The derivative financial assets and liabilities on the Condensed Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

The following table summarizes the income statement change in fair value for the three and nine months ended September 30, 2021 and 2020:


	Three months ended September 30,				Nine months ended September 30,				Income Statement
Gain/(Loss) ($ thousands)	2021		2020		2021		2020		Presentation
Equity Swaps	$	323	$	(384)	$	1,598	$	(1,819)	G&A expense
Commodity Derivative Instruments:
Oil		(1,772)		(18,830)		(200,319)		15,104	Commodity derivative
Gas		(14,725)		—		(27,425)		—	instruments
Total	$	(16,174)	$	(19,214)	$	(226,146)	$	13,285

The following table summarizes the effect of Enerplus’ commodity derivative instruments on the Condensed Consolidated Statements of Income/(Loss):


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Unrealized change in fair value gain/(loss)	$	(16,497)	$	(18,830)	$	(227,744)	$	15,104
Net realized gain/(loss)		(62,450)		19,724		(119,013)		106,236
Commodity derivative instruments gain/(loss)	$	(78,947)	$	894	$	(346,757)	$	121,340

The following table summarizes the fair values of derivative financial instruments at the respective period ends:


	September 30, 2021				December 31, 2020
	Liabilities				Assets			Liabilities
($ thousands)	Current		Long-term		Current			Current	Long-term
Equity Swaps	$	2,015	$	—	$	—	$	3,613	$	—
Commodity Derivative Instruments:
Oil		216,558		42,025		—		15,648		—
Gas		23,085		788		3,550		—		—
Total	$	241,658	$	42,813	$	3,550	$	19,261	$	—

On March 10, 2021, the outstanding crude oil contracts acquired with the Bruin acquisition were recorded at fair value, resulting in a liability of $96.5 million on the Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in the Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the closing date of the Bruin acquisition. At September 30, 2021, the fair value of the remaining Bruin contracts was a liability of $82.6 million, including $42.6 million of the original $96.5 million liability acquired. For the three and nine months ended September 30, 2021 the Company recorded a realized loss of $10.3 million and $11.9 million, respectively, on the settlement of the Bruin contracts. In addition, the Company recognized an unrealized loss of $4.6 million and $40.0 million, respectively, for the change in the fair value of the Bruin contracts over the same periods.

c) Risk Management

i) Market Risk

Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.

Commodity Price Risk:

Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes, net of royalties and production taxes.

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The following tables summarize Enerplus’ price risk management positions at November 3, 2021:

Crude Oil Instruments:


Instrument Type⁽¹⁾⁽²⁾	bbls/day	US$/bbl

Oct 1, 2021 – Dec 31, 2021
WTI Purchased Put	23,000	46.39
WTI Sold Put	23,000	36.39
WTI Sold Call	23,000	56.70

Jan 1, 2022 - Jun 30, 2022
WTI Purchased Put	12,500	75.00
WTI Sold Put	12,500	58.00
WTI Sold Call	12,500	87.63

Jan 1, 2022 - Dec 31, 2022
WTI Purchased Put	17,000	50.00
WTI Sold Put	17,000	40.00
WTI Sold Call	17,000	57.91

Contracts acquired from Bruin⁽³⁾
Oct 1, 2021 – Dec 31, 2021
WTI Swap	7,179	43.01

Jan 1, 2022 - Sep 30, 2022
WTI Swap	4,500	42.31

Oct 1, 2022 - Dec 31, 2022
WTI Swap	1,834	42.65

Jan 1, 2023 - Dec 31, 2023
WTI Swap	208	42.10
WTI Purchased Put	2,000	5.00
WTI Sold Call	2,000	75.00

(1)	The total average deferred premium spent on the Company’s outstanding crude oil contracts is US$0.87/bbl from October 1, 2021 - December 31, 2021 and US$1.29/bbl from January 1, 2022 - December 31, 2022.

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

(3)

Upon closing of the Bruin Acquisition, Bruin’s outstanding crude oil contracts were recorded at a fair value liability of $96.5 million. At September 30, 2021, the balance was a liability of $42.6 million on the Condensed Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition.

Natural Gas Instruments:


Instrument Type⁽¹⁾	MMcf/day	US$/Mcf

Oct 1, 2021 – Oct 31, 2021
NYMEX Swap	60.0	2.90
NYMEX Purchased Put	40.0	2.75
NYMEX Sold Put	40.0	2.15
NYMEX Sold Call	40.0	3.25

Nov 1, 2021 – Mar 31, 2022
NYMEX Purchased Put	40.0	3.43
NYMEX Sold Call	40.0	6.00

Apr 1, 2022 – Oct 31, 2022
NYMEX Swap	40.0	3.40

(1)	Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations and associated net investment, U.S. dollar denominated senior notes, term loan, bank credit facility, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a significant portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At September 30, 2021, Enerplus did not have any foreign exchange derivatives outstanding.

16 ENERPLUS 2021 Q3 REPORT

Enerplus may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited by the cumulative translation gain or loss on the net investment in the foreign subsidiary. At September 30, 2021, US$303.8 million of senior notes outstanding and the US$400 million term loan were designated as net investment hedges. For the three and nine months ended September 30, 2021, Other Comprehensive Income/(Loss) included an unrealized loss of $19.8 million and an unrealized gain of $3.4 million, respectively, on Enerplus’ U.S. dollar denominated senior notes and term loan (2020 – $9.9 million unrealized gain and $20.7 unrealized million loss, respectively).

Interest Rate Risk:

The Company’s senior notes bear interest at fixed rates while the term loan and bank credit facility bear interest at floating rates. At September 30, 2021, approximately 35% of Enerplus’ debt was based on fixed interest rates and 65% on floating interest rates (December 31, 2020 – 100% fixed), with weighted average interest rates of 4.4% and 1.9%, respectively (December 31, 2020 – 4.4%). At September 30, 2021, Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 16. Enerplus has entered into various equity swaps maturing in 2021 that effectively fix the future settlement cost on a portion of its cash settled LTI plans.

ii) Credit Risk

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables. Enerplus has appropriate policies and procedures in place to manage its credit risk; however, given the volatility in commodity prices, Enerplus is subject to an increased risk of financial loss due to non-performance or insolvency of its counterparties.

Enerplus mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At September 30, 2021, approximately 84% of Enerplus’ marketing receivables were with companies considered investment grade (December 31, 2020 – 82%).

Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts of future payments or seeking other remedies including legal action. Enerplus’ allowance for doubtful accounts balance at September 30, 2021 was $4.9 million (December 31, 2020 – $3.6 million).

iii) Liquidity Risk & Capital Management

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and cash equivalents) and shareholders’ equity. Enerplus’ objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current crude oil and natural gas assets and planned investment opportunities.

Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, as well as acquisition and divestment activity.

At September 30, 2021, Enerplus was in full compliance with all covenants under the bank credit facility, term loan, and outstanding senior notes. If the Company breaches or anticipates breaching its covenants, the Company may be required to repay, refinance, or renegotiate the terms of the debt.

ENERPLUS 2021 Q3 REPORT 17

18) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Accounts receivable	$	(48,094)	$	43,832	$	(192,847)	$	111,091
Other assets		(8,175)		(831)		(6,435)		(1,031)
Accounts payable		29,305		12,826		42,463		(13,031)
Non-cash operating activities	$	(26,964)	$	55,827	$	(156,819)	$	97,029

b) Changes in Non-Cash Financing Working Capital


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Non-cash financing activities⁽¹⁾	$	—	$	—	$	(2,225)	$	8

(1)	Relates to changes in dividends payable and included in dividends on the Condensed Consolidated Statements of Cash Flows.

c) Changes in Non-Cash Investing Working Capital


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Non-cash investing activities⁽¹⁾	$	(15,465)	$	(11,013)	$	36,676	$	(37,912)

(1)	Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Condensed Consolidated Statements of Cash Flows, excluding the Bruin and Dunn County acquisitions.

d) Cash Income taxes and Interest payments


	Three months ended September 30,				Nine months ended September 30,
($ thousands)	2021		2020		2021		2020
Cash income taxes paid/(received)	$	954	$	(29,068)	$	5,196	$	(59,164)
Cash interest paid		4,583		3,227		22,979		19,481

Other

During the three-month period ended September 30, 2021, Enerplus, received a $5.7 million distribution associated with a privately held investment. This distribution is recorded within Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss), and reflected as an investing activity in the Condensed Consolidated Statements of Cash Flows.

19) COMMITMENTS

Effective August 1, 2021, Enerplus participated in the Dakota Access Pipeline expansion by contracting another 6,500 bbls/day of firm transportation commitments on the pipeline. The additional transportation provides access to sell a greater portion of Enerplus’ production at U.S. Gulf Coast and Brent pricing.

20) SUBSEQUENT EVENT

On August 30, 2021, the Company announced it had entered into a definitive agreement to sell its interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, for total consideration of US$115 million, subject to customary purchase price adjustments. In addition, the Company may receive up to US$5 million in contingent payments if the WTI oil price averages over US$65 per barrel in 2022 and over US$60 per barrel in 2023. The disposition closed on November 2, 2021.

18 ENERPLUS 2021 Q3 REPORT

Enerplus (ERF) 6-KCurrent report (foreign)