Enerplus announces second quarter 2021 results; increases dividend by 15%

August 5, 2021 3:35 PM

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

CALGARY, AB – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported its second quarter 2021 operating and financial results and an increase to its dividend. Cash flow from operating activities for the second quarter was $136.9 million and adjusted funds flow was $184.3 million, compared to $90.6 million and $70.0 million, respectively, in the second quarter of 2020. Cash flow from operating activities and adjusted funds flow increased compared to the same period in 2020 due to higher production and commodity prices during the second quarter of 2021.

HIGHLIGHTS

Successfully closed the strategic acquisition of assets in the Williston Basin from Hess Corporation on April 30, 2021
Achieved record production in the second quarter of 115,351 BOE per day, 26% higher than the prior quarter
Adjusted funds flow was $184.3 million in the second quarter, which exceeded capital spending of $129.9 million, generating free cash flow of $54.4 million
Annual average 2021 production guidance revised to 112,000 to 115,000 BOE per day, including 69,500 to 71,500 barrels per day of liquids, reflecting higher mid-points, with no change in 2021 capital spending guidance
Increasing return of capital to shareholders: quarterly dividend increased 15% to $0.038 per share; reinitiating share repurchase program
Capital efficiencies continuing to improve: well costs in North Dakota are tracking US$5.7 million per well, a 25% reduction compared to 2019
2021 Bakken crude oil price differential guidance strengthened to US$2.35 per barrel below WTI (from US$3.25)
Estimated 2021 free cash flow of over $450 million based on current forward strip commodity prices
Net debt to adjusted funds flow ratio estimated to be at or below 1.0x by year-end 2021 based on current forward strip commodity prices

“Our second quarter results reflect the increasing scale of our business and continued strong operational momentum,” said Ian C. Dundas, President and CEO. “We delivered record production, capital efficiency gains along with an increasing free cash flow profile. The 15% increase to our quarterly dividend—our second dividend increase this year—and resumption of our share repurchase program underscores our commitment to providing increasing capital returns to shareholders. While we are prioritizing debt reduction in the near term, we will continue to evaluate returning incremental free cash flow to shareholders and are well positioned to meaningfully enhance our shareholder returns upon achieving our $400 million debt reduction target.”

SECOND QUARTER SUMMARY

Production in the second quarter of 2021 was 115,351 BOE per day, an increase of 32% compared to the same period a year ago, and 26% higher than the prior quarter. Crude oil and natural gas liquids production in the second quarter of 2021 was 71,693 barrels per day, an increase of 49% compared to the same period a year ago, and 46% higher than the prior quarter. The increased production compared to the same period in 2020 was due to the contribution from the Company’s Williston Basin acquisitions in 2021 and lower production during the second quarter of 2020 due to reduced activity and temporarily curtailed volumes in response to the low crude oil prices.

Enerplus reported a second quarter 2021 net loss of $59.7 million, or $0.23 per share, compared to a net loss of $609.3 million, or $2.74 per share, in the same period in 2020 which included non-cash impairments. The net loss recognized in the second quarter of 2021 was primarily due to non-cash mark to market losses related to commodity derivative instruments. Adjusted net income for the second quarter of 2021 was $67.9 million, or $0.26 per share, compared to an adjusted net loss of $41.2 million, or $0.19 per share, during the same period in 2020. Adjusted net income was higher compared to the same period in 2020 due to higher commodity prices and increased production.

Enerplus’ second quarter 2021 realized Bakken oil price differential was US$2.76 per barrel below WTI, compared to US$4.36 per barrel below WTI in the second quarter of 2020. Bakken crude oil differentials improved relative to the prior year period due to increased U.S. refinery demand and significant available pipeline capacity in the basin.

The Company’s realized Marcellus natural gas price differential was US$0.89 per Mcf below NYMEX during the second quarter of 2021 compared to US$0.49 per Mcf below NYMEX in the second quarter of 2020. The weaker second quarter 2021 differential reflected significant unplanned regional pipeline maintenance.

In the second quarter of 2021, Enerplus’ operating expenses were $8.43 per BOE, compared to $6.84 per BOE during the same period in 2020. Operating expenses in the second quarter of 2020 were impacted by price-related production curtailments and lower well servicing activity.

Second quarter transportation costs were $3.45 per BOE and cash general and administrative (“G&A”) expenses were $1.04 per BOE.

Enerplus recorded a current tax expense of $4.2 million in the second quarter of 2021 related to U.S. federal taxes as a result of higher expected income in 2021.

Exploration and development capital spending was $129.9 million in the second quarter of 2021. The Company paid $11.0 million in dividends in the quarter.

Enerplus closed its strategic acquisition of certain assets in the Williston Basin from Hess Corporation on April 30, 2021, for total cash consideration of US$312 million, subject to customary purchase price adjustments.

At the end of the second quarter of 2021, the Company had total debt of $1,208.1 million and cash on hand of $75.3 million. Enerplus made principal repayments of US$81.6 million on its 2009 and 2012 senior notes during the quarter.

ASSET ACTIVITY

Williston Basin production averaged 72,390 BOE per day (73% crude oil) during the second quarter of 2021, an increase of 64% compared to the same period a year ago, and 53% higher than the prior quarter. During the second quarter the Company drilled four gross operated wells (100% working interest) and brought 23 gross operated wells on production (83% average working interest). Enerplus continued to drive capital efficiency improvements through faster drilling and completions cycle times and other efficiencies. Enerplus set a company record in the second quarter drilling a two-mile lateral section in 48 hours (lateral spud to total depth). Total well costs in North Dakota are now expected to average US$5.7 million per well in 2021, a reduction of 25% compared to 2019 levels and well below the 2021 target of US$6.1 million.

Marcellus production averaged 192 MMcf per day during the second quarter of 2021, a decrease of 3% compared to the same period in 2020, and 6% lower than the prior quarter.

Canadian waterflood production averaged 7,240 BOE per day (95% crude oil) during the second quarter of 2021, an increase of 14% compared to the same period in 2020, and 2% lower than the prior quarter.

FREE CASH FLOW PRIORITIES

Enerplus expects to allocate approximately 90% of its free cash flow, after dividends, to debt reduction. The Company is targeting a net debt to adjusted funds flow ratio at or below 1.0x assuming a $50 per barrel WTI oil price environment, representing a debt reduction target of approximately $400 million from second quarter 2021 levels. Enerplus estimates it will achieve its debt reduction target by mid-2022 based on current forward strip commodity prices. The remaining approximately 10% of free cash flow, after dividends, is expected to be allocated to incremental capital returns to shareholders, including potential dividend increases and share repurchases. The Company will continue to evaluate this free cash flow allocation as it makes progress on its debt reduction target with the expectation of increasing the allocation of free cash flow to shareholders once its debt target is achieved, assuming a supportive commodity price environment.

Given the Company’s significant increase in cash flow generation following its strategic acquisitions in the first half of 2021, Enerplus believes the business can support a higher dividend while continuing to prioritize debt reduction. As a result, the Board of Directors has approved a 15% increase to the Company’s quarterly dividend to $0.038 per share payable on September 15, 2021 to shareholders of record on August 31, 2021. This is Enerplus’ second dividend increase year to date and represents a 27% increase, on an annualized basis, from the Company’s dividend level at the start of the year.

Enerplus also received approval from its Board of Directors to commence a Normal Course Issuer Bid (“NCIB”), subject to approval by the Toronto Stock Exchange (“TSX”). The proposed renewal will be for 10% of the public float (within the meaning under the TSX rules).

FIVE-YEAR OUTLOOK UPDATE

Enerplus has updated year one (2021) of its five-year outlook to reflect year to date commodity prices and the forward strip for the remainder of the year. The years 2022 to 2025 continue to be based on US$50 to US$55 per barrel WTI flat oil price assumptions. Based on this, the Company has increased the estimated cumulative free cash flow over this period to approximately $1.5 to $2.0 billion.

2021 GUIDANCE UPDATE

Enerplus revised its 2021 average production guidance to 112,000 to 115,000 BOE per day, including liquids production of 69,500 to 71,500 barrels per day due to outperformance year to date. Capital spending guidance is unchanged.

Enerplus narrowed its 2021 Bakken crude oil price differential guidance to US$2.35 per barrel below WTI, compared to US$3.25 per barrel below WTI previously. The improved differential guidance is due to strong year to date pricing and additional firm capacity on the Dakota Access Pipeline (“DAPL”) secured in connection with the pipeline’s expansion. Enerplus now has approximately 10,000 barrels per day of firm transportation on DAPL.

As a result of ongoing pipeline maintenance in the Marcellus, Enerplus widened its 2021 Marcellus natural gas price differential to US$0.65 per Mcf below NYMEX, compared to US$0.55 per Mcf below NYMEX previously.

The Company expects to incur current income tax expense of US$5 million to US$7 million in 2021.

A summary of the Company’s 2021 guidance is provided below.

2021 Guidance

Capital spending	$360 to $400 million
Average annual production	112,000 – 115,000 BOE/day (from 111,000 – 115,000 BOE/day)
Average annual crude oil and natural gas liquids production	69,500 – 71,500 bbls/day (from 68,500 – 71,500 bbls/day)
Average royalty and production tax rate	26%
Operating expense	$8.25/BOE
Transportation expense	$3.85/BOE
Cash G&A expense	$1.25/BOE
Current Income Tax expense	US$5 – $7 million

2021 Full-Year Differential/Basis Outlook⁽¹⁾

U.S. Bakken crude oil differential (compared to WTI crude oil)⁽²⁾	US$(2.35)/bbl (from US$(3.25)/bbl)
Marcellus natural gas sales price differential (compared to NYMEX natural gas)	US$(0.65)/Mcf (from US$(0.55)/Mcf)

(1)	Excluding transportation costs.
(2)	Based on the continued operation of the Dakota Access Pipeline.

Risk Management

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

Enerplus’ Financial Commodity Hedging Contracts (As at August 4, 2021)

WTI Crude Oil ⁽¹⁾⁽²⁾

(US$/bbl)

NYMEX Natural Gas

(US$/Mcf)

Jul 1, 2021 –

Jan 1, 2022 –

Jan 1, 2023 –

Nov 1, 2023 –

Jul 1, 2021 –

Nov 1, 2021 –

Dec 31, 2021

Dec 31, 2022

Oct 31, 2023

Dec 31, 2023

Oct 31, 2021

Mar 31, 2022

Swaps

Volume (bbls/day)

–

60,000

–

Swaps

–

$ 2.90

–

Collars

Volume (bbls/day)

23,000

17,000

–

40,000

Sold Puts

$ 36.39

$ 40.00

–

$ 2.15

–

Purchased Puts

$ 46.39

$ 50.00

–

$ 2.75

$ 3.43

Sold Calls

$ 56.70

$ 57.91

–

$ 3.25

$ 6.00

Hedges acquired from Bruin⁽³⁾

Swaps

Volume (bbls/day)

8,465

3,828

250

–

Swaps

$ 42.52

$ 42.35

$ 42.10

–

Collars

Volume (bbls/day)

–

2,000

–

Purchased Puts

–

$ 5.00

–

Sold Calls

–

$ 75.00

–

(1)	The total average deferred premium spent on outstanding hedges is US$0.84/bbl from July 1, 2021 – December 31, 2021 and US$1.22/bbl from January 1, 2022 – December 31, 2022.
(2)	Transactions with a common term have been aggregated and presented at weighted average prices and volumes.
(3)	Upon closing of the Bruin Acquisition, Bruin’s outstanding hedges were recorded at a fair value liability of $96.5 million. At June 30, 2021, the fair value of the Bruin hedges was a liability of $100.0 million. For the three and six months ended June 30, 2021 we recorded a realized loss of $2.2 million and $1.7 million, respectively, on the settlement of the Bruin hedges. In Addition, we recognized an unrealized loss of $52.8 million and $35.4 million, respectively, for the change in the fair value of the Bruin hedges over the same periods. See Note 17 to the Q2 2021 Financial Statements for further detail.

SECOND QUARTER PRODUCTION AND Operational summary tables

Average Daily Production⁽¹⁾

Three months ended June 30, 2021

Six months ended June 30, 2021

Williston
Basin

Marcellus

Canadian
Water-floods

Other⁽²⁾

Total

Williston
Basin

Marcellus

Canadian
Water-floods

Other⁽²⁾

Total

Tight oil (bbl/d)

52,896

–

1,900

54,797

43,743

–

1,347

45,090

Light & medium oil (bbl/d)

–

2,912

2,998

–

2,970

3,035

Heavy oil (bbl/d)

–

3,983

4,008

–

4,045

4,063

Total crude oil (bbl/d)

52,896

–

6,895

2,012

61,803

43,743

–

7,015

1,429

52,188

Natural gas liquids (bbl/d)

9,257

–

129

504

9,890

7,634

–

535

8,245

Shale gas (Mcf/d)

61,418

191,602

–

1,535

254,555

51,300

197,760

–

1,337

250,396

Conventional natural gas (Mcf/d)

–

1,296

6,093

7,389

–

1,238

7,230

8,467

Total natural gas (Mcf/d)

61,418

191,602

1,296

7,628

261,945

51,300

197,760

1,238

8,566

258,863

Total production (BOE/d)

72,390

31,934

7,240

3,786

115,351

59,928

32,960

7,297

3,392

103,576

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Drilled⁽¹⁾

	Three months ended June 30, 2021				Six months ended June 30, 2021
	Operated		Non-Operated		Operated		Non-Operated
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Williston Basin	4	4.0	–	–	4	4.0	–	–
Marcellus	–	–	14	0.6	–	–	28	0.8
Canadian Waterfloods	–	–	–	–	–	–	–	–
Other⁽²⁾	–	–	–	–	–	–	2	0.3
Total	4	4.0	14	0.6	4	4.0	30	1.1

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Brought On-Stream⁽¹⁾

	Three months ended June 30, 2021				Six months ended June 30, 2021
	Operated		Non-Operated		Operated		Non-Operated
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Williston Basin	23	19.1	1	0.4	26	22.1	1	0.4
Marcellus	–	–	20	1.4	–	–	36	1.8
Canadian Waterfloods	–	–	–	–	–	–	–	–
Other⁽²⁾	–	–	–	–	3	2.6	2	0.3
Total	23	19.1	21	1.8	29	24.7	39	2.5

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Q2 2021 Conference Call Details

A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) on Friday, August 6, 2021 to discuss these results. Details of the conference call are as follows:

Date:	Friday, August 6, 2021
Time:	9:00 AM MT (11:00 AM ET)
Dial-In:	587-880-2171 (Alberta)
	1-888-390-0546 (Toll Free)
Conference ID:	07577276
Audiocast:	https://produceredition.webcasts.com/starthere.jsp?ei=1470850&tp_key=75a2e3927a

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

Replay Dial-In:	1-888-390-0541 (Toll Free)
Replay Passcode:	577276 #

SELECTED FINANCIAL RESULTS	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Financial (CDN$, thousands, except ratios)
Net Income/(Loss)	$	(59,664)	$	(609,323)	$	(44,967)	$	(606,447)
Adjusted Net Income/(Loss)⁽¹⁾		67,932		(41,185)		124,183		(20,095)
Cash Flow from Operating Activities		136,902		90,560		174,141		213,299
Adjusted Funds Flow⁽¹⁾		184,320		69,997		312,435		183,224
Dividends to Shareholders – Declared		11,040		6,675		18,405		13,345
Total Debt Net of Cash⁽¹⁾		1,132,841		518,094		1,132,841		518,094
Capital Spending		129,903		40,084		195,434		203,709
Property and Land Acquisitions		408,764		3,416		1,037,332		5,672
Property Divestments		(17)		(63)		4,978		5,515
Net Debt to Adjusted Funds Flow Ratio⁽¹⁾⁽²⁾		2.3x		1.0x		2.3x		1.0x

Financial per Weighted Average Shares Outstanding
Net Income /(Loss) – Basic	$	(0.23)	$	(2.74)	$	(0.18)	$	(2.73)
Net Income/(Loss) – Diluted		(0.23)		(2.74)		(0.18)		(2.73)
Weighted Average Number of Shares Outstanding (000’s) – Basic		256,750		222,557		250,443		222,457
Weighted Average Number of Shares Outstanding (000’s) – Diluted		256,750		222,557		250,443		222,457

Selected Financial Results per BOE⁽³⁾⁽⁴⁾
Crude Oil & Natural Gas Sales⁽⁵⁾	$	48.60	$	19.53	$	46.38	$	26.11
Royalties and Production Taxes		(12.58)		(5.15)		(11.74)		(6.74)
Commodity Derivative Instruments		(3.53)		6.73		(3.02)		5.12
Operating Expenses		(8.43)		(6.84)		(8.16)		(7.90)
Transportation Costs		(3.45)		(4.28)		(3.68)		(4.11)
Cash General and Administrative Expenses		(1.04)		(1.14)		(1.28)		(1.26)
Cash Share-Based Compensation		(0.22)		(0.15)		(0.27)		0.09
Interest, Foreign Exchange and Other Expenses		(1.39)		(1.69)		(1.34)		(1.29)
Current Income Tax Recovery/(Expenses)		(0.40)		1.81		(0.22)		0.85
Adjusted Funds Flow⁽¹⁾	$	17.56	$	8.82	$	16.67	$	10.87

	Three months ended June 30,				Six months ended June 30,
SELECTED OPERATING RESULTS	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Average Daily Production⁽⁴⁾
Crude Oil (bbls/day)		61,803		43,168		52,187		46,106
Natural Gas Liquids (bbls/day)		9,890		4,929		8,245		5,137
Natural Gas (Mcf/day)		261,945		235,579		258,863		249,246
Total (BOE/day)		115,351		87,360		103,576		92,784

% Crude Oil and Natural Gas Liquids		62%		55%		58%		55%

Average Selling Price⁽⁴⁾⁽⁵⁾
Crude Oil (per bbl)	$	76.67	$	30.55	$	72.90	$	41.59
Natural Gas Liquids (per bbl)		22.72		(0.96)		28.06		6.16
Natural Gas (per Mcf)		2.45		1.63		2.96		1.87

Net Wells Drilled		5		3		5		37

(1)	These are non–GAAP measures that do not have any standardized meaning under the Company’s GAAP and, therefore, may not be directly comparable to similar measures presented by other entities. See “Non–GAAP Measures” section in the news release.
(2)	Ratio does not include trailing adjusted funds flow from the recent Williston Basin acquisitions.
(3)	Non-cash amounts have been excluded.
(4)	Based on Company interest production volumes. See “Presentation of Production Information” below.
(5)	Before transportation costs, royalties, and commodity derivative instruments.

Condensed Consolidated Balance Sheets

(CDN$ thousands) unaudited	June 30, 2021		December 31, 2020
Assets
Current Assets
Cash and cash equivalents	$	75,278	$	114,455
Accounts receivable		252,316		106,376
Derivative financial assets		—		3,550
Other current assets		7,505		7,137
		335,099		231,518
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)		1,680,329		575,559
Other capital assets, net		18,912		19,524
Property, plant and equipment		1,699,241		595,083
Right-of-use assets		36,951		32,853
Deferred income tax asset		600,257		607,001
Total Assets	$	2,671,548	$	1,466,455

Liabilities
Current liabilities
Accounts payable	$	379,255	$	251,822
Dividends payable		—		2,225
Current portion of long-term debt		98,688		103,836
Derivative financial liabilities		225,696		19,261
Current portion of lease liabilities		12,940		13,391
		716,579		390,535
Derivative financial liabilities		64,536		—
Long-term debt		1,109,431		386,586
Asset retirement obligation		160,201		130,208
Lease liabilities		27,668		23,446
		1,361,836		540,240
Total Liabilities		2,078,415		930,775

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2021 – 257 million shares December 31, 2020 – 223 million shares		3,236,117		3,096,969
Paid-in capital		36,269		50,604
Accumulated deficit		(2,995,389)		(2,932,017)
Accumulated other comprehensive income/(loss)		316,136		320,124
		593,133		535,680
Total Liabilities & Shareholders’ Equity	$	2,671,548	$	1,466,455

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

	Three months ended				Six months ended
	June 30,				June 30,
(CDN$ thousands, except per share amounts) unaudited	2021		2020		2021		2020
Revenues
Crude oil and natural gas sales, net of royalties	$	408,622	$	122,069	$	697,423	$	350,196
Commodity derivative instruments gain/(loss)		(197,967)		(10,895)		(267,810)		120,446
		210,655		111,174		429,613		470,642
Expenses
Operating		88,459		54,353		152,981		133,373
Transportation		36,188		34,006		69,011		69,335
Production taxes		30,502		7,687		47,954		23,131
General and administrative		12,474		13,494		28,746		32,679
Depletion, depreciation and accretion		93,908		79,885		140,368		175,077
Asset impairment		—		426,810		4,300		426,810
Goodwill impairment		—		202,767		—		202,767
Interest		9,527		7,051		16,350		15,962
Foreign exchange (gain)/loss		6,864		1,493		6,986		(4,144)
Transaction costs and other expense/(income)		(718)		6,301		3,806		6,072
		277,204		833,847		470,502		1,081,062
Income/(Loss) before taxes		(66,549)		(722,673)		(40,889)		(610,420)
Current income tax expense/(recovery)		4,175		(14,422)		4,175		(14,395)
Deferred income tax expense/(recovery)		(11,060)		(98,928)		(97)		10,422
Net Income/(Loss)	$	(59,664)	$	(609,323)	$	(44,967)	$	(606,447)

Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation		(14,345)		(57,284)		(27,212)		74,490
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax		14,702		19,466		23,224		(30,596)
Total Comprehensive Income/(Loss)	$	(59,307)	$	(647,141)	$	(48,955)	$	(562,553)

Net income/(Loss) per share
Basic	$	(0.23)	$	(2.74)	$	(0.18)	$	(2.73)
Diluted	$	(0.23)	$	(2.74)	$	(0.18)	$	(2.73)

Condensed Consolidated Statements of Cash Flows

	Three months ended				Six months ended
	June 30,				June 30,
(CDN$ thousands) unaudited	2021		2020		2021		2020
Operating Activities
Net income/(loss)	$	(59,664)	$	(609,323)	$	(44,967)	$	(606,447)
Non-cash items add/(deduct):
Depletion, depreciation and accretion		93,908		79,885		140,368		175,077
Asset impairment		—		426,810		4,300		426,810
Goodwill impairment		—		202,767		—		202,767
Changes in fair value of derivative instruments		160,130		63,929		209,972		(32,499)
Deferred income tax expense/(recovery)		(11,060)		(98,928)		(97)		10,422
Foreign exchange (gain)/loss on debt and working capital		5,539		1,038		5,858		(1,377)
Share-based compensation and general and administrative		(23)		3,428		990		11,183
Other expenses/(income)		(2,353)		—		(2,353)		—
Amortization of debt issuance costs		312		—		385		—
Translation of U.S. dollar cash held in Canada		(2,469)		391		(2,021)		(2,712)
Asset retirement obligation settlements		(1,359)		(333)		(8,439)		(11,127)
Changes in non-cash operating working capital		(46,059)		20,896		(129,855)		41,202
Cash flow from/(used in) operating activities		136,902		90,560		174,141		213,299

Financing Activities
Bank term loan		—		—		501,286		—
Bank credit facility		333,616		1,364		333,616		1,364
Repayment of senior notes		(99,348)		(114,010)		(99,348)		(114,010)
Proceeds from the issuance of shares		—		—		125,746		—
Purchase of common shares under Normal Course Issuer Bid		—		—		—		(2,536)
Share-based compensation – cash settled (tax withholding)		—		—		(4,491)		(7,232)
Dividends		(13,608)		(6,676)		(20,627)		(13,337)
Cash flow from/(used in) financing activities		220,660		(119,322)		836,182		(135,751)

Investing Activities
Capital and office expenditures		(92,422)		(104,111)		(144,184)		(233,453)
Bruin acquisition		(2,537)		—		(531,134)		—
Dunn County acquisition		(374,613)		—		(374,613)		—
Property and land acquisitions		(1,619)		(3,416)		(5,026)		(5,672)
Property divestments		(17)		(63)		4,978		5,515
Cash flow from/(used in) investing activities		(471,208)		(107,590)		(1,049,979)		(233,610)
Effect of exchange rate changes on cash & cash equivalents		(92)		453		479		10,590
Change in cash and cash equivalents		(113,738)		(135,899)		(39,177)		(145,472)
Cash and cash equivalents, beginning of period		189,016		142,076		114,455		151,649
Cash and cash equivalents, end of period	$	75,278	$	6,177	$	75,278	$	6,177

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

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

Barrels of Oil Equivalent

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

Presentation of Production Information

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

FORWARD-LOOKING INFORMATION AND STATEMENTS

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

The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated, including considering the Hess asset and Bruin acquisition; that our development plans will achieve the expected results; that a lack of adequate infrastructure and/or low commodity price environment will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and estimated commodity prices, differentials and cost assumptions; the continued ability to operate DAPL; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including expectations regarding the duration and overall impact of COVID-19; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to comply with our debt covenants; the availability of third party services; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement obligations; the availability of technology and processes to achieve environmental targets. In addition, Enerplus’ 2021 outlook contained in this news release is based on the following rest of year prices: US$69/bbl WTI, US$3.92/Mcf NYMEX, and a USD/CDN exchange rate of 1.26. Furthermore, in addition, years 2022 to 2025 of Enerplus’ five-year outlook contained in this news release is based on the following: a WTI price of between US$50.00/bbl and US$55.00/bbl, a NYMEX price of US$2.75/Mcf and a USD/CDN exchange rate of 1.27. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued instability, or further deterioration, in global economic and market environment, including from COVID-19; continued low commodity price environment or further 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; failure to realize the anticipated benefits of the Hess asset and Bruin acquisitions; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings in connection with DAPL; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; changes in law or government programs or policies in Canada or the United States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies described under “Risk Factors and Risk Management” in Enerplus’ 2020 MD&A and in our other public filings).

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

NON-GAAP MEASURES

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

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

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

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Enerplus announces second quarter 2021 results; increases dividend by 15%

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