Enerplus announces fourth quarter and full year 2022 financial and operating results; 2023 guidance; updates five-year outlook through 2027

February 23, 2023 3:30 PM

All financial information contained within this news release has been prepared in accordance with U.S. GAAP and is presented in U.S. dollars. This news release includes forward-looking statements and information within the meaning of applicable securities laws. Production information, unless otherwise stated, is presented on a net basis (after deduction of royalty obligations). Readers are advised to review the “Forward-Looking Information and Statements” at the conclusion of this news release. Readers are also referred to “Notice Regarding Information Contained in this News Release” and “Non-GAAP and Other Financial Measures” at the end of this news release for information regarding the presentation of the financial and operational information in this news release, as well as the use of certain financial measures that do not have standard meaning under U.S. GAAP. A copy of Enerplus’ 2022 Financial Statements and MD&A is available on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov. All amounts in this news release are stated in United States dollars unless otherwise specified.

CALGARY, AB – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported fourth quarter 2022 cash flow from operating activities and adjusted funds flow of $316.6 million and $315.4 million, respectively, compared to $283.5 million and $258.5 million, respectively, in the fourth quarter of 2021. Full year 2022 cash flow from operating activities and adjusted funds flow was $1,173.4 million and $1,230.3 million, respectively, compared to $604.8 million and $712.4 million, respectively, in 2021.

HIGHLIGHTS – FULL YEAR 2022

Generated adjusted funds flow of $1,230.3 million in 2022, which exceeded capital spending of $432.0 million, generating free cash flow⁽¹⁾ of $798.3 million.
Reduced net debt by 65% from year-end 2021, ending 2022 with net debt of $221.5 million.
Returned $452.5 million to shareholders through dividends and share repurchases, representing 57% of 2022 free cash flow.
Reduced shares outstanding by 11% during 2022, compared to year-end 2021.
Delivered 2022 average production of 100,326 BOE per day, 9% higher than 2021 (17% higher than 2021 on a per share basis).
Completed the divestment of substantially all its Canadian assets during 2022 for total consideration of $278.9 million (CDN$380.4 million), before purchase price adjustments.
Replaced 112% of 2022 net production through net proved reserves additions (U.S. SEC Standards) and 139% of 2022 gross production through gross proved plus probable reserves additions (Canadian NI 51-101 Standards). See separate news release issued today.

⁽¹⁾	This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information.

“Enerplus delivered strong operational and financial results in 2022 marked by production outperformance, effective cost control, and robust free cash flow generation,” said Ian C. Dundas, President and CEO. “Our liquids production increased 10%, exceeding expectations, while our solid execution and procurement dampened the impacts of inflation allowing us to operate within our original capital guidance range. We generated approximately $800 million of free cash flow, returning over half to shareholders and reducing our net debt by 65%. This performance has left us well positioned in 2023 where our focus will remain on developing our high-quality Bakken position under a capital efficient operating plan expected to deliver attractive free cash flow and continued value creation.”

FOURTH QUARTER 2022 SUMMARY

Total production for the fourth quarter of 2022 was 106,915 BOE per day, an increase of 4% compared to the same period in 2021. Liquids production in the fourth quarter was 65,356 barrels per day, an increase of 1% compared to the same period in 2021. Strong well performance supported the higher year-over-year production in the fourth quarter of 2022 despite weather downtime in North Dakota in December and the divestment of the company’s Canadian operations in the quarter. The Company’s fourth quarter production was in line with its total and liquids production guidance of 105,000 to 110,000 BOE per day and 64,000 to 68,000 barrels per day, respectively.

In the Williston Basin, Enerplus drilled ten operated wells (88% average working interest) and brought five operated wells on production (96% average working interest). Williston Basin production averaged approximately 72,100 BOE per day (70% crude oil) in the quarter. Marcellus production averaged 181 MMcf per day in the quarter.

Enerplus reported fourth quarter 2022 net income of $330.7 million, or $1.43 per share (diluted), compared to net income of $176.9 million, or $0.68 per share (diluted), in the fourth quarter of 2021. Excluding certain non-cash or non-recurring items, fourth quarter 2022 adjusted net income⁽¹⁾ was $181.1 million, or $0.78 per share (diluted), compared to $130.0 million, or $0.50 per share (diluted), during the same period in 2021. The increase in net income and adjusted net income was primarily due to higher production and commodity prices.

Enerplus’ fourth quarter 2022 Bakken crude oil price differential was $1.05 per barrel above WTI, compared to $0.88 per barrel below WTI for the same period in 2021. Bakken crude oil prices continued to trade at a premium to 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. Enerplus’ fourth quarter 2022 Marcellus natural gas price differential was $1.18 per Mcf below NYMEX, compared to $1.70 per Mcf below NYMEX for the same period in 2021. The narrower differential was due to stronger regional prices entering the winter season in 2022.

Operating expenses in the fourth quarter of 2022 were $9.68 per BOE, compared to $8.46 per BOE in the same period in 2021. The increase in per unit operating expenses was primarily due to the impacts 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 were $1.15 per BOE in the fourth quarter of 2022, compared to $1.12 per BOE in the prior year period.

Current tax expense was $3.1 million in the fourth quarter.

Capital spending totaled $85.6 million in the fourth quarter. The Company paid $12.2 million in dividends during the quarter and repurchased 9.8 million common shares at an average price of $17.24 per common share for a total cost of $169.0 million.

Enerplus ended the fourth quarter with net debt of $221.5 million and had a net debt to adjusted funds flow ratio of 0.2 times.

⁽¹⁾	This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information.

FULL YEAR 2022 SUMMARY

Total production for 2022 was 100,326 BOE per day, an increase of 9% compared to 2021. Liquids production in 2022 was 61,698 barrels per day, an increase of 10% compared to 2021. The higher year-over-year production was due to development activity in North Dakota and the Marcellus, strong well performance, and the benefit of a full year of production from the Company’s acquisitions in North Dakota. The Company’s 2022 production was in line with its total and liquids production guidance of 99,750 to 101,000 BOE per day and 61,500 to 62,500 barrels per day, respectively.

Enerplus reported full year 2022 net income of $914.3 million, or $3.77 per share (diluted), compared to net income of $234.4 million, or $0.90 per share (diluted), in 2021. Excluding certain non-cash or non-recurring items, 2022 adjusted net income⁽¹⁾ was $707.1 million, or $2.91 per share (diluted), compared to $315.7 million, or $1.21 per share (diluted), in 2021. The higher net income and adjusted net income was primarily due to higher production and commodity prices.

Enerplus’ 2022 Bakken crude oil price differential was $1.09 per barrel above WTI, compared to $2.15 per barrel 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. Enerplus’ 2022 Marcellus natural gas price differential was $0.72 per Mcf below NYMEX, compared to $0.81 per Mcf below NYMEX in 2021, due to both inventory and supply concerns, particularly in Europe, given the reduction in natural gas supply from Russia slightly offset by lower Northeast U.S. demand during the fall shoulder season.

Operating expenses in 2022 were $9.99 per BOE, compared to $8.69 per BOE in 2021. The increase in per BOE operating expenses was primarily due to the impacts 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 in 2022 were $1.17 per BOE, compared to $1.14 per BOE in 2021.

Current tax expense was $28.1 million in 2022.

Capital spending totaled $432.0 million in 2022, in line with the Company’s guidance of $430 million. The Company paid $41.6 million in dividends in 2022 and repurchased 27.9 million common shares at an average price of $14.71 per common share for a total cost of $410.9 million.

⁽¹⁾	This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE

Enerplus continued to make progress on its ESG initiatives in 2022. Based on preliminary estimates and relative to its 2021 baseline, the Company reduced 2022 methane emissions intensity by 9% and scope 1 and 2 greenhouse gas (“GHG”) emissions intensity by 16%. The Company continues to work towards its longer-term environmental targets, including methane intensity reduction targets of 30% and 50% by 2025 and 2030, respectively, and a scope 1 and 2 GHG emissions intensity reduction target of 35% by 2030, in each case relative to the applicable 2021 baseline. As part of its emissions reduction strategy, Enerplus is participating in an electrification project in North Dakota and has allocated approximately $10 million towards the project in 2023 (included in the Company’s capital spending guidance).

Since 2020, Enerplus has achieved a three-year average of an 80% reduction in Lost Time Injury Frequency (“LTIF”) relative to its 2019 baseline. Enerplus is targeting a 25% reduction in LTIF on average from 2020 to 2023, relative to its 2019 baseline.

2023 GUIDANCE

Enerplus’ 2023 capital spending guidance is $500 to $550 million, which is allocated approximately 95% to North Dakota, 2.5% to the Marcellus and 2.5% to the DJ Basin.

Consistent with its five-year outlook, the Company expects to deliver approximately 3% to 5% annual liquids production growth in 2023 after adjusting for the sale of substantially all of its Canadian assets in the fourth quarter of 2022 with associated production of 6,400 BOE per day (78% liquids). The Company’s 2023 liquids production guidance is 57,000 to 61,000 barrels per day.

Activity in Enerplus’ non-operated Marcellus natural gas position is expected to be significantly lower in 2023 with capital spending anticipated to be down over 70% year-over-year. Enerplus expects to participate in drilling 2.0 to 2.5 net wells and completing 1.0 to 1.5 net wells in 2023. As a result of the limited activity, Marcellus production is projected to be 8% lower in 2023, compared to 2022.

Overall, the Company’s 2023 total production guidance is 93,000 to 98,000 BOE per day.

Operating cost guidance in 2023 is $10.75 to $11.75 per BOE, reflecting an increase from 2022 due to inflation adjusted contract prices and general cost escalation, increased gas processing volumes due to improved capture rates, and higher well-service activity.

Cash tax guidance in 2023 is 5% to 6% of adjusted funds flow before tax based on a commodity price environment of $80 per barrel WTI and $3.50 per Mcf NYMEX. Based on the same commodity price assumptions, Enerplus expects to generate approximately $475 million of free cash flow in 2023.

Operating plan

Under a two-rig program, Enerplus expects to drill 55 to 60 gross operated wells (86% average working interest) and bring 45 to 55 gross operated wells (87% average working interest) on production in North Dakota during the year. The Company expects its 2023 total well costs to increase approximately 10% year-over-year to $7.8 million, largely due to inflationary pressures. In addition, Enerplus has allocated a portion of its North Dakota budget to refrac opportunities in Dunn County and non-operated activity.

Enerplus also plans to drill and bring on production 4 gross operated wells (46% working interest) in the DJ Basin in 2023.

2023 capital spending is expected to be weighted approximately 60% to the first half of the year.

The table below summarizes Enerplus’ 2023 guidance.

2023 Guidance Summary

Capital spending	$500 – $550 million
Average total production	93,000 – 98,000 BOE/day
Average liquids production	57,000 – 61,000 bbls/day
Average production tax rate (% of net sales, before transportation)	7 %
Operating expense	$10.75 – $11.75/BOE
Transportation expense	$4.35/BOE
Cash G&A expense	$1.35/BOE
Current tax expense	5% – 6% of adjusted funds flow, before tax

2023 Differential/Basis Outlook⁽¹⁾

U.S. Bakken crude oil differential (compared to WTI crude oil)	$0.75/bbl
Marcellus natural gas sales price differential (compared to NYMEX natural gas)	$(0.75)/Mcf

⁽¹⁾	Excluding transportation costs.

RETURN OF CAPITAL TO SHAREHOLDERS

As previously announced, Enerplus expects to return at least 60% of free cash flow generated in 2023 to shareholders through dividends and share repurchases. Based on current market conditions, the Company expects to continue to prioritize share repurchases for the majority of its return of capital plans due to its assessment that its intrinsic value is not adequately reflected in its current trading value. Despite an expected 2023 free cash flow profile weighted to the second half of the year, Enerplus intends to accelerate a portion of its second half free cash flow into its return of capital plans during the first half of 2023.

Subsequent to December 31, 2022 and up to and including February 22, 2023, Enerplus repurchased 1.4 million common shares at an average price of $16.65 per common share for a total cost of $23.7 million. As at February 22, 2023, Enerplus had 6.5 million shares remaining for repurchase under its normal course issuer bid authorization which can be renewed in August 2023 for up to 10% of the public float (within the meaning under the TSX rules).

Enerplus announced a quarterly cash dividend of $0.055 per share payable on March 15, 2023, to all shareholders of record at the close of business on March 6, 2023. This quarterly dividend represents $48 million on an annualized basis.

Remaining free cash flow not allocated to return of capital is expected to be directed to reinforcing the balance sheet.

UPDATED 5-YEAR OUTLOOK (2023-2027)

Enerplus has updated its five-year outlook to include 2027 and to reflect the ongoing inflationary environment. The Company’s outlook continues to be underpinned by a focus on strong and safe operational execution, low financial leverage and attractive free cash flow generation. The plan is also supported by over ten years of high-returning drilling inventory in North Dakota.

The Company projects annual capital spending of $500 to $550 million and is expected to deliver 3% to 5% annual liquids production growth. The five-year outlook is expected to have an average reinvestment rate of approximately 50% based on commodity price assumptions of $80 per barrel WTI and $4.00 per Mcf NYMEX⁽¹⁾.

⁽¹⁾	2023 is based on forward strip commodity prices.

BOARD OF DIRECTORS RETIREMENTS

Enerplus would like to acknowledge Susan (Sue) MacKenzie and Robert (Bob) Hodgins for their long standing service to the Enerplus Board. Each have notified the board of directors that they intend to retire at the end of the current term and will not stand for re-election.

“On behalf of the board and company, I would like to thank Sue and Bob for their commitment and many impactful contributions over the years,” said Hilary Foulkes, Chair of the Board of Directors of Enerplus. “Sue and Bob were appointed to the Enerplus board in 2011 and 2007, respectively. During their tenure they individually brought deep expertise to their committee leadership and board roles, and provided valuable perspectives which helped guide Enerplus through a period of meaningful change.”

Q4 AND FULL YEAR 2022 CONFERENCE CALL DETAILS

Enerplus plans to hold a conference call at 9:00 a.m. MT (11:00 a.m. ET) on February 24, 2023 to discuss these results. Details of the conference call are as follows:

Date: Friday, February 24, 2023
Time: 9:00 am MT/11:00 am ET
Webcast: https://app.webinar.net/rN3M9rlpK0A

To immediately join the conference call by phone, without operator assistance, please use the following URL to register and be connected into the conference call by automated call back: https://bit.ly/3GJLs24.

To join the call from a live operator managed queue, please dial 1-888-390-0546 (Toll Free) using conference ID 48151534.

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

Dial-In: 416-764-8677
1-888-390-0541 (toll free)
Passcode: 151534 #

PRICE RISK MANAGEMENT UPDATE

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 hedges 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.

FOURTH QUARTER AND FULL YEAR 2022 PRODUCTION AND OPERATIONAL SUMMARY TABLES

Summary of Average Daily Production⁽¹⁾

	Three months ended December 31, 2022					Twelve months ended December 31, 2022
	Williston Basin	Marcellus	Canadian Water- floods	Other⁽²⁾	Total	Williston Basin	Marcellus	Canadian Water- floods	Other⁽²⁾	Total
Light & medium oil (bbl/d)	–	–	1,465	47	1,512	–	–	1,917	33	1,950
Heavy oil (bbl/d)	–	–	1,649	19	1,668	–	–	2,541	16	2,556
Tight oil (bbl/d)	50,652	–	–	769	51,421	46,706	–	–	805	47,511
Total crude oil (bbl/d)	50,652	–	3,114	835	54,601	46,706	–	4,458	853	52,017

Natural gas liquids (bbl/d)	10,569	–	15	171	10,755	9,333	–	73	275	9,681

Conventional natural gas (Mcf/d)	–	–	472	1,851	2,323	–	–	1,170	4,755	5,925
Shale gas (Mcf/d)	65,134	181,126	–	767	247,028	55,987	168,947	–	911	225,845
Total natural gas (Mcf/d)	65,134	181,126	472	2,618	249,350	55,987	168,947	1,170	5,666	231,770

Total production (BOE/d)	72,077	30,188	3,208	1,442	106,915	65,370	28,158	4,725	2,073	100,326

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

Summary of Wells Drilled⁽¹⁾

	Three months ended December 31, 2022				Twelve months ended December 31, 2022
	Operated		Non-Operated		Operated		Non-Operated
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Williston Basin	10	8.8	4	0.8	45	38.8	43	7.0
Marcellus	–	–	19	0.2	–	–	81	5.5
DJ Basin	–	–	–	–	–	–	15	0.4
Total	10	8.8	23	1.1	45	38.8	139	12.9

(1)	Table may not add due to rounding.

Summary of Wells Brought On-Stream⁽¹⁾

	Three months ended December 31, 2022				Twelve months ended December 31, 2022
	Operated		Non-Operated		Operated		Non-Operated
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Williston Basin	5	4.8	8	2.5	39	35.5	48	7.8
Marcellus	–	–	38	2.8	–	–	96	6.8
DJ Basin	–	–	–	–	–	–	12	0.3
Total	5	4.8	46	5.2	39	35.5	156	15.0

(1)	Table may not add due to rounding.

SUMMARY FINANCIAL AND OPERATING RESULTS


SELECTED FINANCIAL RESULTS	Three months ended December 31,				Twelve months ended 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


SELECTED OPERATING RESULTS	Three months ended December 31,				Twelve months ended 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 financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this news release.
(2)	Non–cash amounts have been excluded.
(3)	Based on net production volumes. See “Presentation of Production and Reserves Information” section in this news release.
(4)	Before transportation costs and commodity derivative instruments.

Condensed Consolidated Balance Sheets


(US$ thousands)	December 31, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	38,000	$	61,348
Accounts receivable		276,590		227,988
Other current assets		56,552		10,956
Derivative financial assets		36,542		5,668
		407,684		305,960
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)		1,322,904		1,253,505
Other capital assets		10,685		13,887
Property, plant and equipment		1,333,589		1,267,392
Other long-term assets		21,154		9,756
Right-of-use assets		20,556		26,118
Deferred income tax asset		154,998		380,858
Total Assets	$	1,937,981	$	1,990,084

Liabilities
Current liabilities
Accounts payable	$	398,482	$	367,008
Current portion of long-term debt		80,600		100,600
Derivative financial liabilities		10,421		143,200
Current portion of lease liabilities		13,664		10,618
		503,167		621,426
Long-term debt		178,916		601,171
Asset retirement obligation		114,662		132,814
Derivative financial liabilities		—		7,098
Lease liabilities		9,262		18,265
Deferred income tax liability		55,361		—
Total Liabilities		861,368		1,380,774

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: December 31, 2022 – 217 million shares
December 31, 2021 – 244 million shares		2,837,329		3,094,061
Paid-in capital		50,457		50,881
Accumulated deficit		(1,509,832)		(2,238,325)
Accumulated other comprehensive loss		(301,341)		(297,307)
		1,076,613		609,310
Total Liabilities & Shareholders’ Equity	$	1,937,981	$	1,990,084

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


For the year ended December 31 (US$ thousands)	2022		2021		2020
Revenues
Crude oil and natural gas sales	$	2,353,374	$	1,482,575	$	553,739
Commodity derivative instruments gain/(loss)		(197,686)		(274,432)		75,742
		2,155,688		1,208,143		629,481
Expenses
Operating		365,701		292,433		197,097
Transportation		154,658		128,309		98,681
Production taxes		166,995		101,953		37,417
General and administrative		69,954		56,807		43,097
Depletion, depreciation and accretion		309,367		271,336		218,118
Asset impairment		—		3,420		751,723
Goodwill impairment		—		—		149,217
Interest		24,553		27,395		20,737
Foreign exchange (gain)/loss		10,159		(6,908)		1,232
Gain on divestment of assets		(151,937)		—		—
Transaction costs and other expense/(income)		(1,360)		(2,487)		4,489
		948,090		872,258		1,521,808
Income/(Loss) Before Taxes		1,207,598		335,885		(892,327)
Current income tax expense/(recovery)		28,063		2,689		(10,716)
Deferred income tax expense/(recovery)		265,233		98,755		(188,260)
Net Income/(Loss)	$	914,302	$	234,441	$	(693,351)

Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation		22,507		(6,893)		(2,169)
Foreign exchange gain/(loss) on net investment hedge, net of tax		(26,541)		4,097		1,780
Total Comprehensive Income/(Loss)	$	910,268	$	231,645	$	(693,740)

Net Income/(Loss) per Share
Basic	$	3.91	$	0.93	$	(3.12)
Diluted	$	3.77	$	0.90	$	(3.12)

Condensed Consolidated Statements of Cash Flows


For the year ended December 31 (US$ thousands)	2022		2021		2020
Operating Activities
Net income/(loss)	$	914,302	$	234,441	$	(693,351)
Non-cash items add/(deduct):
Depletion, depreciation and accretion		309,367		271,336		218,118
Asset impairment		—		3,420		751,723
Goodwill impairment		—		—		149,217
Changes in fair value of derivative instruments		(150,526)		109,536		18,074
Deferred income tax expense/(recovery)		265,233		98,755		(188,260)
Foreign exchange (gain)/loss on debt and working capital		11,217		(8,055)		1,363
Share-based compensation and general and administrative		22,529		13,424		9,508
Other expense/(income)		(4,137)		(4,594)		—
Amortization of debt issuance costs		1,476		1,093		—
Translation of U.S. dollar cash held in parent company		(937)		(2,330)		(902)
Gain on divestment of assets		(151,937)		—		—
Other expense/(income) reclassified to Investing Activities		13,702		(4,593)		—
Asset retirement obligation settlements		(17,401)		(12,951)		(13,275)
Changes in non-cash operating working capital		(39,506)		(94,643)		83,669
Cash flow from/(used in) operating activities		1,173,382		604,839		335,884

Financing Activities
Drawings from/(repayment of) bank credit facilities		(340,650)		400,000		—
Repayment of senior notes		(100,600)		(81,600)		(81,600)
Debt issuance costs		(1,005)		(4,621)		—
Purchase of common shares under Normal Course Issuer Bid		(410,906)		(123,182)		(1,807)
Proceeds from the issuance of shares		—		98,339		—
Share-based compensation – tax withholdings settled in cash		(13,386)		(3,551)		(5,567)
Dividends		(41,597)		(32,284)		(19,897)
Cash flow from/(used in) financing activities		(908,144)		253,101		(108,871)

Investing Activities
Capital and office expenditures		(429,873)		(271,131)		(248,990)
Bruin acquisition		—		(420,249)		—
Dunn County acquisition		—		(305,076)		—
Canadian divestments		158,033		—		—
Property and land acquisitions		(22,515)		(9,846)		(7,491)
Property and land divestments		18,385		108,193		4,456
Other (expense)/income		(13,702)		4,593		—
Cash flow from/(used in) investing activities		(289,672)		(893,516)		(252,025)
Effect of exchange rate changes on cash and cash equivalents		1,086		6,979		(1,786)
Change in cash and cash equivalents		(23,348)		(28,597)		(26,798)
Cash and cash equivalents, beginning of year		61,348		89,945		116,743
Cash and cash equivalents, end of year	$	38,000	$	61,348	$	89,945

[expand title=”Advisories & Contact”]About Enerplus

Enerplus is an independent North American oil and gas exploration and production company focused on creating long-term value for its shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations. For more information, visit the Company’s website at www.enerplus.com.

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

NOTICE REGARDING INFORMATION CONTAINED IN THIS NEWS RELEASE

Currency and Accounting Principles

All amounts in this news release are stated in U.S. 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 and Other Financial Measures”.

Barrels of Oil Equivalent

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

Presentation of Production and Reserves Information

All production volumes presented in this news release are reported on a “net” basis (the Company’s working interest share after deduction of royalty obligations, plus the Company’s royalty interests), unless expressly indicated that it is being presented on a “gross” basis.
All reserves information presented herein are reported 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”), except 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 U.S. Securities and Exchange Commission (collectively, the “U.S. Rules”), 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”). The practice of preparing production and reserves data under the Canadian NI 51-101 Standards differs from the U.S. Rules and the presentation of production and reserves data under the Canadian Standards differs from presentation under the U.S. Standards. Please refer to our reserves news release dated as of the date hereof for further information.

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 NGLs on a combined basis. All references to “natural gas” in this news release include conventional natural gas and shale gas on a combined basis.

The calculation for production per share growth uses average annual production divided by the weighted average number of shares outstanding in each year. The weighted average number of shares outstanding was 251.9 million in 2021 and 233.9 million in 2022.

Enerplus’ oil and gas reserves statement for the year ended December 31, 2022, which will include complete disclosure of our oil and gas reserves and other oil and gas information prepared under the Canadian NI 51-101 Standards and also certain information about our oil and gas reserves prepared in accordance with the U.S. Rules, is contained within our Annual Information Form (AIF) for the year ended December 31, 2022 which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on EDGAR concurrently with this news release for more complete disclosure on our operations.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release 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”, “intend”, “plans”, “budget”, “strategy” 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 2023 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, including expected changes to such differentials year-over-year, 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; share repurchase plans and the amount of future cash returns to our shareholders by way of dividends and share repurchases; 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; he amount of future cash dividends that we may pay to our shareholders and the source of funds necessary in order to pay such dividends; execution of our remaining NCIB authorization and any future share repurchases and the anticipated timing thereof; expected reinvestment rates; capital spending levels and allocations in 2023 and impact thereof on our production levels and land holdings; our ESG initiatives, including Scope 1 and Scope 2 GHG emissions and methane emissions intensity and health and safety targets; our anticipated progress towards our ESG initiatives, including timing and expected capital expenditures needed to achieve such targets; future environmental expenses; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with, renegotiate or renew our bank credit facilities and outstanding senior notes, as applicable; and our future acquisitions and dispositions.

The forward-looking information contained in this news release 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; 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; expectations regarding inflation; 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; expectations regarding our share price; 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; our ability to meet the targets associated with our bank credit facilities; the availability of third party services; the extent of our liabilities; estimates relating to our ESG emissions intensity; and the availability of technology and process to achieve environmental targets; the ability to achieve the expected benefits of the divestment of the Sleeping Giant and Russian Creek interests in the Williston Basin on Enerplus’ operations, reserves, inventory and opportunities, financial condition and overall strategy. In addition, our 2023 guidance contained in this news release 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/USD 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 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 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; failure to realize the anticipated benefits of the divestment of the Canadian assets; 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 identified in our MD&A, AIF and Form 40-F as at December 31, 2022).

The forward-looking information contained in this news release speaks only as of the date of this news 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 AND OTHER FINANCIAL MEASURES

Non-GAAP Financial Measures

This news release 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

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).

Electronic copies of Enerplus’ 2022 MD&A and Financial Statements, along with other public information including investor presentations, are available on the Company’s website at www.enerplus.com. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com

[/expand]

Enerplus announces fourth quarter and full year 2022 financial and operating results; 2023 guidance; updates five-year outlook through 2027

Latest Headlines