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, Feb. 23, 2023 /CNW/ - 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
|
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
SOURCE Enerplus Corporation