All financial information contained within this news release
has been prepared in accordance with U.S. GAAP. This news release
includes forward-looking statements and information within the
meaning of applicable securities laws. Readers are advised to
review the "Forward-Looking Information and Statements" at the
conclusion of this news release. 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' 2021 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.
Reporting currency changed to U.S. dollars; production
volumes changed to a "net" (after deduction of royalty) basis as
announced on February 2,
2022.
CALGARY, AB, Feb. 24, 2022 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today
reported fourth quarter 2021 cash flow from operating
activities and adjusted funds flow(1) of $283.5 million and $258.5
million, respectively, compared to $70.9 million and $68.6
million, respectively, in the fourth quarter of 2020. Full
year 2021 cash flow from operating activities and adjusted funds
flow(1) was $604.8 million
and $712.4 million, respectively,
compared to $335.9 million and
$265.5 million, respectively, in
2020.
HIGHLIGHTS - FULL YEAR 2021
- Robust free cash flow generation – Adjusted funds
flow(1) was $712.4 million
in 2021, which exceeded capital spending of $302.3 million, generating free cash
flow(1) of $410.1 million
(representing a reinvestment rate(1) of 42%).
- Strategic Bakken acquisitions – Completed two highly
accretive and strategic acquisitions in the Bakken in 2021 which
have enhanced Enerplus' free cash flow generation and extended the
Company's high quality drilling inventory to over a decade.
- Maintained balance sheet strength – Ended 2021 with net
debt(1) of $640.4 million
and a net debt to adjusted funds flow ratio(1) of
0.9x.
- Meaningful capital returned to shareholders – Increased
the dividend by 37% and repurchased $123.2
million of the Company's shares in 2021 for a total cash
return to shareholders of $153.7
million.
- Strong performance relative to emissions targets –
Continued progress towards Enerplus' 50% greenhouse gas ("GHG")
emissions intensity reduction target by 2030 (Scope 1 and 2).
Relative to its 2019 baseline, the Company reduced methane
emissions intensity by over 20% in 2021 (one year ahead of target)
and reduced 2021 GHG emissions intensity by approximately 25%,
based on preliminary estimates.
- Capital efficiency improvement – Solid operational
execution delivered another significant reduction in total well
cost performance in North Dakota
which averaged $5.7 million per well
in 2021, down 10% year-over-year.
- Substantial reserves growth – Year end 2021 net proved
reserves increased 163% year-over-year (U.S. SEC Standards), and
gross proved plus probable reserves increased 45% year-over-year
(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.
|
HIGHLIGHTS – 2022 AND FIVE-YEAR OUTLOOK
- 2022 free cash flow outlook – At commodity prices
of $75 per barrel WTI and
$4.00 per Mcf NYMEX, Enerplus expects
to generate approximately $500
million of free cash flow(1) in 2022,
representing a reinvestment rate(1) of less than
45%.
- Increased share repurchase plan – Based on current
market conditions, Enerplus plans to execute its remaining Normal
Course Issuer Bid ("NCIB") authorization by the end of July 2022. This represents an increase to the
Company's current CDN$200 million
repurchase program by approximately $100
million, assuming Enerplus' current share price. Upon
completion, this is expected to result in over $300 million in total cash returns to
shareholders over the preceding 12-month period through dividends
and share repurchases.
- Updated five-year outlook – Extended through 2026 and
under commodity price assumptions of $70 per barrel WTI and $3.00 per Mcf NYMEX (2), Enerplus
projects $2.2 billion of cumulative
free cash flow(1) under annual capital spending of
$400 to $450
million. Liquids production is expected to grow by 3% to 5%
annually.
(1) This is a non-GAAP financial
measure. Refer to "Non-GAAP and Other Financial Measures" section
for more information.
|
(2) 2022 is based on $75/bbl WTI and
$4.00/Mcf NYMEX.
|
"2021 was a transformational year for Enerplus. We completed two
highly strategic and accretive acquisitions, maintained our
commitment to operating with low financial leverage, and generated
company record production and free cash flow," said Ian C. Dundas, President and CEO.
"The depth of our North Dakota
inventory and our operational scale have substantially increased
following our 2021 acquisitions. We can point to over a decade of
high-quality North Dakota drilling
inventory, which further supports the sustainability of our
long-term plan," commented Dundas.
"Looking ahead, we are positioned to deliver another year of
strong results supported by high commodity prices, a capital
efficient operating plan in North
Dakota that is 75% protected from cost inflation, and
structurally tight Bakken oil price differentials. Consistent with
our track record, we expect to deliver meaningful cash returns to
shareholders in 2022. We continue to believe that our intrinsic
value, based on mid-cycle commodity price assumptions, is not
adequately reflected in our current market value. As a result, we
plan to continue our aggressive approach to share repurchases which
is expected to result in a reduction to our shares outstanding of
approximately 10% in less than a year since commencing the
program."
FOURTH QUARTER 2021 SUMMARY
Enerplus delivered fourth quarter total production of 102,823
BOE per day, which was at the high end of its guidance range
(100,000 to 103,200 BOE per day). Total production in the fourth
quarter was 4% higher than the prior quarter and 48% higher than
the same period in 2020. Liquids production in the fourth quarter
was 64,959 barrels per day, which was in line with the Company's
guidance (64,150 to 66,550 barrels per day). Liquids production in
the fourth quarter was 3% higher than the prior quarter and 63%
higher than the same period in 2020. The higher
quarter-over-quarter production was due to development activity in
North Dakota and the Marcellus.
The higher production compared to the same period in 2020 was
primarily due to the Company's acquisitions in North Dakota completed during the first half
of 2021. Enerplus completed the divestment of its Sleeping Giant
and Russian Creek interests in the Williston Basin during the fourth quarter with
associated production of approximately 2,400 BOE per day.
Enerplus reported fourth quarter 2021 net income of $176.9 million, or $0.71 per share, compared to a net loss of
$161.6 million, or ($0.73) per share, in the fourth quarter of 2020.
Excluding certain non-cash or non-recurring items, fourth quarter
2021 adjusted net income(1) was $130.0 million, or $0.52 per share, compared to $15.3 million, or $0.07 per share, during the same period in 2020.
The higher net income and adjusted net income was primarily due to
higher production and commodity prices. The net loss in the fourth
quarter of 2020 was primarily due to a non-cash property, plant and
equipment ("PP&E") impairment of $244.5
million.
Enerplus' fourth quarter 2021 Bakken crude oil price
differential was $0.88 per barrel
below WTI, compared to
$5.12 per barrel below WTI for the
same period in 2020. The stronger Bakken differential was due to an
improved supply and demand balance and excess pipeline capacity in
the region. Enerplus' fourth quarter Marcellus natural gas price
differential was $1.70 per Mcf below
NYMEX, compared to $1.07 per Mcf
below NYMEX for the same period in 2020. The wider Marcellus
differential was due to volatility in NYMEX pricing and weaker
local markets during the fourth quarter of 2021.
Operating expenses in the fourth quarter of 2021 were
$8.46 per BOE, compared to
$7.82 per BOE in the same period in
2020. The increase in per unit operating expenses was due to the
Company's higher crude oil production, contract price escalation
and increased well service activity. Cash general and
administrative ("G&A") expenses were $1.12 per BOE in the fourth quarter of 2021,
compared to $1.40 per BOE in the
prior year period. The reduction in per unit G&A expenses was
due to higher production in the fourth quarter of 2021.
Capital spending totaled $81.1
million in the fourth quarter of 2021. The Company paid
$7.9 million in dividends during the
quarter and repurchased 11.2 million shares at an average price of
$10.08 (CDN$12.70) per share for a total cost of
$113.3 million.
Enerplus ended the fourth quarter of 2021 with net debt of
$640.4 million and was undrawn on its
$900 million bank credit
facility.
(1) This is a non-GAAP financial
measure. Refer to "Non-GAAP and Other Financial Measures" section
for more information.
|
FULL YEAR 2021 SUMMARY
Enerplus delivered 2021 total production of 92,221 BOE per day,
which was at the high end of its guidance range (91,450 to 92,250
BOE per day). Total production in 2021 was 26% higher compared to
2020. Liquids production in 2021 was 56,337 barrels per day, which
was in line with the Company's guidance (55,950 to 56,750 barrels
per day). Liquids production in 2021 was 37% higher compared to
2020. The higher year-over-year production was primarily due to the
Company's acquisitions in North
Dakota completed during the first half of 2021 and its
development program in 2021.
Enerplus reported full year 2021 net income of $234.4 million, or $0.93 per share, compared to a net loss of
$693.4 million, or ($3.12) per share, in 2020. Excluding certain
non-cash or non-recurring items, 2021 adjusted net
income(1) was $315.7
million, or $1.25 per share,
compared to $14.5 million, or
$0.07 per share, in 2020. The higher
net income and adjusted net income was primarily due to higher
production and commodity prices. The net loss in 2020 was primarily
due to non-cash impairments of $900.9
million as a result of low commodity prices in 2020.
Enerplus' 2021 Bakken crude oil price differential was
$2.15 per barrel below WTI, compared
to $5.39 per barrel below WTI in
2020. Bakken pricing strengthened throughout the year as basin-wide
production fell below 2020 levels, while pipeline egress capacity
out of the basin increased with the Dakota Access Pipeline
expansion start-up in August 2021.
Enerplus' 2021 Marcellus natural gas price differential was
$0.81 per Mcf below NYMEX,
compared to $0.65 per Mcf below NYMEX
in 2020. The weaker pricing was driven by warmer than anticipated
weather for much of the year and volatility in NYMEX benchmark
prices.
Operating expenses in 2021 were $8.69 per BOE, compared to $7.38 per BOE in 2020. Cash G&A expenses in
2021 were $1.14 per BOE, compared to
$1.26 per BOE in 2020.
Capital spending totaled $302.3
million in 2021, in line with the Company's guidance of
$303 million. The Company paid
$30.5 million in dividends in 2021
and repurchased 12.9 million shares at an average price of
$9.55 (CDN$12.06) per share for a total cost of
$123.2 million.
(1) This is a non-GAAP financial
measure. Refer to "Non-GAAP and Other Financial Measures" section
for more information.
|
ASSET ACTIVITY
Williston Basin production
averaged 67,590 BOE per day during the fourth quarter of 2021, 4%
higher than the prior quarter. In the fourth quarter, Enerplus
drilled six operated wells (100% working interest) and brought
eight operated wells on production (100% working interest).
Enerplus continued to deliver reductions to its well cost
structures in 2021 through improved execution and technology
application. This led to a 10% improvement year-over-year in total
well costs which averaged $5.7
million in 2021.
Marcellus production averaged 161 MMcf per day during the fourth
quarter of 2021, 5% higher than the prior quarter. Canadian
waterflood production averaged 5,741 BOE per day during the fourth
quarter of 2021, 2% lower than the prior quarter.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE
Enerplus continued to make strong progress on its ESG
initiatives in 2021. Based on preliminary estimates, the Company
expects to have reduced its 2021 scope 1 and 2 GHG emissions
intensity by approximately 25% and its methane emissions
intensity by over 20%, each compared to a 2019 baseline. Enerplus
also reduced its freshwater use per well completion in the Fort
Berthold Indian Reservation by 31% in 2021, compared to a 2019
baseline, exceeding its target of 25%. The Company continues to
work towards its longer-term environmental targets, including a 50%
reduction in GHG emissions intensity by 2030 and a 50% reduction in
freshwater use per well completion corporately by 2025.
Enerplus is also well positioned to achieve its safety targets
having delivered a company record in 2021 of zero lost time
injuries. Enerplus is targeting a 25% reduction in lost time injury
frequency, on average, from 2020 to 2023, relative to its 2019
baseline.
2022 GUIDANCE AND FREE CASH FLOW OUTLOOK
Enerplus' previously announced 2022 preliminary outlook was
$400 million of capital spending
expected to result in production of approximately 98,000 BOE per
day, including 60,000 barrels per day of liquids. Enerplus has
provided formal 2022 guidance of $370
to $430 million of capital spending,
total production of 95,500 to 100,500 BOE per day, and liquids
production of 58,000 to 62,000 barrels per day.
At commodity prices of $75 per
barrel WTI and $4.00 per Mcf NYMEX,
Enerplus expects to generate approximately $500 million of free cash flow(1) in
2022, representing a reinvestment rate(1) of less than
45%. Enerplus remains committed to both reducing debt and returning
a significant portion of free cash flow to shareholders.
Increasing return of capital to shareholders
Enerplus
has a long track record of returning capital to shareholders
throughout the cycle. Since 2017, Enerplus has returned over 60% of
its free cash flow(1), or $435
million, to shareholders through dividends and share
repurchases.
Upon completion of the Company's CDN$200
million share repurchase program, which is expected by the
end of the first quarter of 2022, Enerplus plans to repurchase the
remaining authorization under its NCIB by the end of July 2022, based on current market conditions.
Using Enerplus' current share price, this equates to additional
share repurchases of approximately $100
million and, when fully executed, will represent
approximately 10% of the Company's shares outstanding having been
repurchased since the third quarter of 2021. Inclusive of dividends
and share repurchases, the Company expects to have returned over
$300 million to shareholders over the
12-month period ending July 2022. The
Company intends to renew its NCIB in August
2022.
Operating plan
The Company has added a second drilling
rig in North Dakota which it plans
to operate for approximately six months, reverting to one drilling
rig in the second half of 2022. Enerplus expects to drill 46 to 54
gross operated wells (79% average working interest) and bring 36 to
44 gross operated wells (87% average working interest) on
production in North Dakota during
the year. In total, the Company expects to allocate 83% of its 2022
capital budget to North Dakota
which includes approximately $80
million for non-operated North
Dakota activity.
The remaining 17% of the Company's 2022 capital spending is
expected to be allocated to the Marcellus (10%), the Canadian
Waterfloods (4%) and the DJ Basin (3%).
With strong demand and significant available pipeline capacity
in the basin, Enerplus expects its 2022 realized Bakken oil price
differential to strengthen year-over-year. The Company expects its
2022 Bakken oil price differential to average $0.50 per barrel below WTI.
Operating costs are expected to increase in 2022 to $9.50 to $10.50 per
BOE, compared to $8.69 per BOE in
2021. The expected increase is primarily due to contract price
escalation (linked to the Consumer Price Index), increased sales
gas processing volumes due to improved capture rates, and higher
well-service activity.
The table below summarizes Enerplus' 2022 guidance. The
Company's 2022 guidance has not been adjusted to reflect the
potential divestment of its Canadian assets as announced on
February 2, 2022.
2022 Guidance Summary
Capital
spending
|
$370 – 430
million
|
Average total
production
|
95,500 – 100,500
BOE/day
|
Average liquids
production
|
58,000 – 62,000
bbls/day
|
Average production
tax rate (% of net sales, before transportation)
|
7%
|
Operating
expense
|
$9.50
–10.50/BOE
|
Transportation
expense
|
$4.15/BOE
|
Cash G&A
expense
|
$1.25/BOE
|
Current tax
expense
|
$10
million
|
2022 Differential/Basis Outlook(2)
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
$(0.50)/bbl
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
$(0.75)/Mcf
|
|
(1) This is a non-GAAP financial
measure. Refer to "Non-GAAP and Other Financial Measures" section
for more information.
|
(2) Excluding transportation
costs.
|
UPDATED FIVE-YEAR OUTLOOK
Enerplus has updated its five-year outlook to include 2026 and
to reflect the higher current commodity price and inflationary
environment. Enerplus' previous five-year outlook (provided in
2021) was based on a commodity price environment of $50 to $55 per
barrel WTI and $2.75 per Mcf NYMEX.
Enerplus is extending its outlook through 2026 and increasing its
commodity price assumptions to $70
per barrel WTI and $3.00 per Mcf
NYMEX(1). The Company's outlook continues to be
underpinned by a focus on operating with low financial leverage,
delivering strong and sustainable free cash flow growth, and
returning capital to shareholders.
The Company projects annual capital spending of between
$400 to $450
million with cumulative free cash flow(2)
estimated at over $2.2 billion
between 2022 and 2026. This is expected to result in an average
reinvestment rate(2) of approximately 50% over the
period. Enerplus projects 3% to 5% annual liquids production growth
over this period (2022 annual growth is higher due to timing
impacts of the 2021 acquisitions).
(1) 2022 is based on $75/bbl WTI and
$4.00/Mcf NYMEX.
|
(2) This is a non-GAAP financial
measure. Refer to "Non-GAAP and Other Financial Measures" section
for more information.
|
QUARTERLY DIVIDEND DECLARED
Enerplus changed its dividend declaration currency to U.S.
dollars consistent with its change in reporting currency. The
Company declared a quarterly cash dividend of $0.033 per share, equivalent to approximately
CDN$0.042 per share if converted
using the current US/Canadian dollar exchange rate of 1.28. The
dividend is effective with the March 15,
2022 dividend payment and applies to all shareholders of
record at the close of business on March 4,
2022. The ex-dividend date for this payment is March 3, 2022.
Q4 AND FULL YEAR 2021 CONFERENCE CALL DETAILS
Enerplus plans to hold a conference call at 9:00 a.m. MT (11:00 a.m.
ET) on February 25, 2022 to
discuss these results. Details of the conference call are as
follows:
Date:
|
Friday, February 25,
2022
|
Time:
|
9:00 am MT/11:00 am
ET
|
Dial-In:
|
416-764-8688
1-888-390-0546 (toll free)
|
Conference
ID:
|
57309809
|
Audiocast:
|
https://produceredition.webcasts.com/starthere.jsp?ei=1519306&tp_key=08cd734c3e
|
|
|
To ensure timely
participation in the conference call, callers are encouraged to
dial in 15 minutes prior to the start time to register for the
event. A telephone replay will be available for 30 days following
the conference call and can be accessed at the following
numbers:
|
|
|
|
Dial-In:
|
416-764-8677
|
|
1-888-390-0541 (toll
free)
|
Passcode:
|
546758 #
|
PRICE RISK MANAGEMENT UPDATE
The following is a summary of Enerplus' financial contracts in
place at February 24, 2022:
|
|
WTI Crude Oil
($/bbl)(1)(2)(3)
|
|
NYMEX Natural Gas
($/Mcf)
|
|
|
Jan 1,
2022 –
|
|
Jan 1,
2022 –
|
|
Jan 1, 2023
–
|
|
Jan 1,
2023 –
|
|
Jan 1,
2022 –
|
Mar 1 ,
2022 –
|
Apr 1,
2022 –
|
|
|
Jun 30,
2022
|
|
Dec 31,
2022
|
|
Jun 30,
2023
|
|
Dec 31,
2023
|
|
Feb 28,
2022
|
Mar 31,
2022
|
Oct 31,
2022
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
60,000
|
40,000
|
Sold Puts
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
$ 4.50
|
$ 3.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
12,500
|
|
17,000
|
|
10,000
|
|
2,000
|
|
40,000
|
40,000
|
60,000
|
Sold Puts
|
|
$ 58.00
|
|
$ 40.00
|
|
$ 60.00
|
|
-
|
|
-
|
-
|
-
|
Purchased
Puts
|
|
$ 75.00
|
|
$ 50.00
|
|
$ 76.50
|
|
$ 5.00
|
|
$ 3.43
|
$ 3.43
|
$3.77
|
Sold Calls
|
|
$ 87.63
|
|
$ 57.91
|
|
$ 107.38
|
|
$ 75.00
|
|
$ 6.00
|
$ 6.00
|
$4.50
|
(1)
|
(1) The total average
deferred premium spent on our outstanding hedges is $1.50/bbl from
January 1, 2022 – December 31, 2022 and $1.25/bbl from January 1,
2023 – June 30, 2023.
|
(2)
|
Transactions with a
common term have been aggregated and presented at weighted average
prices and volumes.
|
(3)
|
Upon closing of the
Bruin Acquisition, Bruin's outstanding crude oil contracts were
recorded at a fair value liability of $76.4 million. At December
31, 2021, the remaining balance was a liability of $22.8 million on
the Condensed Consolidated Balance Sheets. Realized and unrealized
gains and losses on the acquired contracts are recognized in
Consolidated Statement of Income/(Loss) and the Consolidated
Balance Sheets to reflect changes in crude oil prices from the date
of closing of the Bruin Acquisition. See Note 17 to the Financial
Statements for a breakdown of the commodity contracts acquired from
Bruin.
|
FOURTH QUARTER AND FULL YEAR 2021 PRODUCTION AND OPERATIONAL
SUMMARY TABLES
Summary of Average Daily Production(1)
|
Three months ended
December 31, 2021
|
|
Twelve months
ended December 31, 2021
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-floods
|
Other(2)
|
Total
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-floods
|
Other(2)
|
Total
|
Light & medium
oil (bbl/d)
|
-
|
-
|
2,160
|
25
|
2,185
|
|
-
|
-
|
2,187
|
44
|
2,231
|
Heavy oil
(bbl/d)
|
-
|
-
|
3,208
|
16
|
3,223
|
|
-
|
-
|
3,282
|
20
|
3,302
|
Tight oil
(bbl/d)
|
49,025
|
-
|
-
|
985
|
50,010
|
|
41,914
|
-
|
-
|
1,067
|
42,981
|
Total crude oil
(bbl/d)
|
49,025
|
-
|
5,368
|
1,026
|
55,419
|
|
41,914
|
-
|
5,469
|
1,131
|
48,514
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
liquids (bbl/d)
|
9,111
|
-
|
99
|
330
|
9,540
|
|
7,379
|
-
|
72
|
372
|
7,823
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional natural
gas (Mcf/d)
|
-
|
-
|
1,644
|
6,353
|
7,997
|
|
-
|
-
|
1,403
|
6,415
|
7,818
|
Shale gas
(Mcf/d)
|
56,726
|
161,432
|
-
|
1,031
|
219,189
|
|
48,440
|
157,946
|
-
|
1,100
|
207,486
|
Total natural gas
(Mcf/d)
|
56,726
|
161,432
|
1,644
|
7,384
|
227,186
|
|
48,440
|
157,946
|
1,403
|
7,515
|
215,304
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production
(BOE/d)
|
67,590
|
26,905
|
5,741
|
2,587
|
102,823
|
|
57,366
|
26,324
|
5,775
|
2,756
|
92,221
|
(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, 2021
|
|
Twelve months
ended December 31, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
6
|
6.0
|
|
19
|
3.4
|
|
18
|
18.0
|
|
37
|
4.0
|
Marcellus
|
-
|
-
|
|
15
|
0.7
|
|
-
|
-
|
|
64
|
2.5
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
3
|
0.4
|
Total
|
6
|
6.0
|
|
34
|
4.2
|
|
18
|
18.0
|
|
104
|
6.9
|
(1) Table may not add due to
rounding.
|
(2) Comprises DJ Basin and
non-core properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended December 31, 2021
|
|
Twelve months
ended December 31, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
8
|
8.0
|
|
22
|
0.9
|
|
50
|
40.1
|
|
27
|
2.0
|
Marcellus
|
-
|
-
|
|
20
|
2.4
|
|
-
|
-
|
|
74
|
4.5
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
2
|
0.1
|
|
3
|
2.6
|
|
5
|
0.4
|
Total
|
8
|
8.0
|
|
44
|
3.4
|
|
53
|
42.7
|
|
106
|
6.9
|
(1) Table may not add due to
rounding.
|
(2) Comprises DJ Basin and
non-core properties in Canada.
|
SUMMARY FINANCIAL AND OPERATING RESULTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED FINANCIAL RESULTS
|
December 31,
|
|
December 31,
|
|
|
2021
|
|
2020
|
|
|
2021
|
|
2020
|
Financial
(US$, thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
176,913
|
|
$
|
(161,566)
|
|
|
$
|
234,441
|
|
$
|
(693,351)
|
Adjusted Net
Income(1)
|
|
|
129,958
|
|
|
15,272
|
|
|
|
315,669
|
|
|
14,522
|
Cash Flow from
Operating Activities
|
|
|
283,534
|
|
|
70,900
|
|
|
|
604,839
|
|
|
335,884
|
Adjusted Funds
Flow(1)
|
|
|
258,477
|
|
|
68,634
|
|
|
|
712,433
|
|
|
265,490
|
Dividends to
Shareholders - Declared
|
|
|
7,884
|
|
|
5,207
|
|
|
|
30,535
|
|
|
19,962
|
Net
Debt(1)
|
|
|
640,423
|
|
|
295,455
|
|
|
|
640,423
|
|
|
295,455
|
Capital
Spending
|
|
|
81,059
|
|
|
40,193
|
|
|
|
302,348
|
|
|
217,246
|
Property and Land
Acquisitions
|
|
|
2,744
|
|
|
1,584
|
|
|
|
835,147
|
|
|
7,492
|
Property
Divestments
|
|
|
108,869
|
|
|
37
|
|
|
|
112,651
|
|
|
4,456
|
Net Debt to Adjusted
Funds Flow Ratio(1)
|
|
|
0.9x
|
|
|
1.1x
|
|
|
|
0.9x
|
|
|
1.1x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) -
Basic
|
|
$
|
0.71
|
|
$
|
(0.73)
|
|
|
$
|
0.93
|
|
$
|
(3.12)
|
Net Income/(Loss) -
Diluted
|
|
|
0.68
|
|
|
(0.73)
|
|
|
|
0.90
|
|
|
(3.12)
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
|
250,359
|
|
|
222,548
|
|
|
|
251,909
|
|
|
222,503
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
|
258,365
|
|
|
222,548
|
|
|
|
259,851
|
|
|
222,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil &
Natural Gas Sales(4)
|
|
$
|
52.82
|
|
$
|
23.45
|
|
|
$
|
44.04
|
|
$
|
20.72
|
Commodity Derivative
Instruments
|
|
|
(7.12)
|
|
|
2.67
|
|
|
|
(4.84)
|
|
|
3.47
|
Operating
Expenses
|
|
|
(8.46)
|
|
|
(7.82)
|
|
|
|
(8.69)
|
|
|
(7.38)
|
Transportation
Costs
|
|
|
(4.27)
|
|
|
(3.70)
|
|
|
|
(3.81)
|
|
|
(3.69)
|
Production
Taxes
|
|
|
(3.47)
|
|
|
(1.58)
|
|
|
|
(3.03)
|
|
|
(1.40)
|
General and
Administrative Expenses
|
|
|
(1.12)
|
|
|
(1.40)
|
|
|
|
(1.14)
|
|
|
(1.26)
|
Cash Share-Based
Compensation
|
|
|
(0.22)
|
|
|
(0.11)
|
|
|
|
(0.20)
|
|
|
0.04
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(0.82)
|
|
|
(0.80)
|
|
|
|
(1.08)
|
|
|
(1.01)
|
Current Income Tax
Recovery/(Expense)
|
|
|
(0.02)
|
|
|
—
|
|
|
|
(0.08)
|
|
|
0.40
|
Adjusted Funds
Flow(1)
|
|
$
|
27.32
|
|
$
|
10.71
|
|
|
$
|
21.17
|
|
$
|
9.89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED OPERATING RESULTS
|
December 31,
|
|
December 31,
|
|
|
2021
|
|
2020
|
|
|
2021
|
|
2020
|
Average Daily
Production(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
55,419
|
|
|
35,118
|
|
|
|
48,514
|
|
|
36,681
|
Natural Gas Liquids
(bbls/day)
|
|
|
9,540
|
|
|
4,615
|
|
|
|
7,823
|
|
|
4,499
|
Natural Gas
(Mcf/day)
|
|
|
227,186
|
|
|
179,265
|
|
|
|
215,304
|
|
|
191,014
|
Total
(BOE/day)
|
|
|
102,823
|
|
|
69,611
|
|
|
|
92,221
|
|
|
73,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
63%
|
|
|
57%
|
|
|
|
61%
|
|
|
56%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(3)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
|
$
|
75.54
|
|
$
|
36.89
|
|
|
$
|
66.05
|
|
$
|
33.30
|
Natural Gas Liquids
(per bbl)
|
|
|
38.90
|
|
|
13.21
|
|
|
|
29.86
|
|
|
7.79
|
Natural Gas
(per Mcf)
|
|
|
4.02
|
|
|
1.57
|
|
|
|
2.98
|
|
|
1.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
|
10
|
|
|
2
|
|
|
|
25
|
|
|
42
|
(1)
|
This financial
measure is a non-GAAP financial measure and may not be directly
comparable to similar measures presented by other
entities. See "Non-GAAP and Other Financial Measures" section
in this MD&A.
|
(2)
|
Non–cash amounts have
been excluded.
|
(3)
|
Based on Net
production volumes. See "Basis of Presentation" section in the
following MD&A.
|
(4)
|
Before transportation
costs and commodity derivative instruments.
|
Condensed Consolidated Balance Sheets
|
|
|
|
|
|
|
(US$ thousands)
|
|
December 31,
2021
|
|
December 31, 2020
|
Assets
|
|
|
|
|
|
|
Current
assets
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
61,348
|
|
$
|
89,945
|
Accounts
receivable
|
|
|
227,988
|
|
|
83,596
|
Other current
assets
|
|
|
10,956
|
|
|
5,609
|
Derivative financial
assets
|
|
|
5,668
|
|
|
2,790
|
|
|
|
305,960
|
|
|
181,940
|
Property, plant and
equipment:
|
|
|
|
|
|
|
Crude oil and natural
gas properties (full cost method)
|
|
|
1,253,505
|
|
|
452,302
|
Other capital
assets
|
|
|
13,887
|
|
|
11,499
|
Property, plant and
equipment
|
|
|
1,267,392
|
|
|
463,801
|
Other long-term
assets
|
|
|
9,756
|
|
|
3,845
|
Right-of-use
assets
|
|
|
26,118
|
|
|
25,818
|
Deferred income tax
asset
|
|
|
380,858
|
|
|
477,014
|
Total
Assets
|
|
$
|
1,990,084
|
|
$
|
1,152,418
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
367,008
|
|
$
|
197,895
|
Dividends
payable
|
|
|
—
|
|
|
1,749
|
Current portion of
long-term debt
|
|
|
100,600
|
|
|
81,600
|
Derivative financial
liabilities
|
|
|
143,200
|
|
|
15,136
|
Current portion of
lease liabilities
|
|
|
10,618
|
|
|
10,523
|
|
|
|
621,426
|
|
|
306,903
|
Long-term
debt
|
|
|
601,171
|
|
|
303,800
|
Asset retirement
obligation
|
|
|
132,814
|
|
|
102,325
|
Derivative financial
liabilities
|
|
|
7,098
|
|
|
—
|
Lease
liabilities
|
|
|
18,265
|
|
|
18,425
|
|
|
|
759,348
|
|
|
424,550
|
Total
Liabilities
|
|
|
1,380,774
|
|
|
731,453
|
|
|
|
|
|
|
|
Shareholders'
Equity
|
|
|
|
|
|
|
Share capital –
authorized unlimited common shares, no par value
|
|
|
|
|
|
|
Issued and
outstanding: December 31, 2021 – 244 million
shares
|
|
|
|
|
|
|
December 31, 2020 – 223 million shares
|
|
|
3,094,061
|
|
|
3,113,829
|
Paid-in
capital
|
|
|
50,881
|
|
|
49,382
|
Accumulated
deficit
|
|
|
(2,238,325)
|
|
|
(2,447,735)
|
Accumulated other
comprehensive loss
|
|
|
(297,307)
|
|
|
(294,511)
|
|
|
|
609,310
|
|
|
420,965
|
Total
Liabilities & Shareholders' Equity
|
|
$
|
1,990,084
|
|
$
|
1,152,418
|
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
|
For the year ended
December 31 (US$ thousands)
|
|
2021
|
|
2020
|
|
2019
|
Revenues
|
|
|
|
|
|
|
|
|
|
Crude oil and natural
gas sales
|
|
$
|
1,482,575
|
|
$
|
553,739
|
|
$
|
945,894
|
Commodity derivative
instruments gain/(loss)
|
|
|
(274,432)
|
|
|
75,742
|
|
|
(47,930)
|
|
|
|
1,208,143
|
|
|
629,481
|
|
|
897,964
|
Expenses
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
292,433
|
|
|
197,097
|
|
|
219,343
|
Transportation
|
|
|
128,309
|
|
|
98,681
|
|
|
109,241
|
Production
taxes
|
|
|
101,953
|
|
|
37,417
|
|
|
62,662
|
General and
administrative
|
|
|
56,807
|
|
|
43,097
|
|
|
54,920
|
Depletion,
depreciation and accretion
|
|
|
271,336
|
|
|
218,118
|
|
|
269,046
|
Asset
impairment
|
|
|
3,420
|
|
|
751,723
|
|
|
—
|
Goodwill
impairment
|
|
|
—
|
|
|
149,217
|
|
|
347,283
|
Interest
|
|
|
27,395
|
|
|
20,737
|
|
|
25,580
|
Foreign exchange
(gain)/loss
|
|
|
(6,908)
|
|
|
1,232
|
|
|
(16,420)
|
Transaction costs and
other expense/(income)
|
|
|
(2,487)
|
|
|
4,489
|
|
|
(5,695)
|
|
|
|
872,258
|
|
|
1,521,808
|
|
|
1,065,960
|
Income/(Loss)
Before Taxes
|
|
|
335,885
|
|
|
(892,327)
|
|
|
(167,996)
|
Current income tax
expense/(recovery)
|
|
|
2,689
|
|
|
(10,716)
|
|
|
(25,246)
|
Deferred income tax
expense/(recovery)
|
|
|
98,755
|
|
|
(188,260)
|
|
|
61,650
|
Net
Income/(Loss)
|
|
$
|
234,441
|
|
$
|
(693,351)
|
|
$
|
(204,400)
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
|
Unrealized
gain/(loss) on foreign currency translation
|
|
|
(6,893)
|
|
|
(2,169)
|
|
|
11,995
|
Foreign exchange
gain/(loss) on net investment hedge, net of tax
|
|
|
4,097
|
|
|
1,780
|
|
|
—
|
Total
Comprehensive Income/(Loss)
|
|
$
|
231,645
|
|
$
|
(693,740)
|
|
$
|
(192,405)
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss)
per Share
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.93
|
|
$
|
(3.12)
|
|
$
|
(0.88)
|
Diluted
|
|
$
|
0.90
|
|
$
|
(3.12)
|
|
$
|
(0.88)
|
Condensed Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
For the year ended
December 31 (US$ thousands)
|
|
2021
|
|
2020
|
|
2019
|
Operating
Activities
|
|
|
|
|
|
|
|
|
|
Net
income/(loss)
|
|
$
|
234,441
|
|
$
|
(693,351)
|
|
$
|
(204,400)
|
Non-cash items
add/(deduct):
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and accretion
|
|
|
271,336
|
|
|
218,118
|
|
|
269,046
|
Asset
impairment
|
|
|
3,420
|
|
|
751,723
|
|
|
—
|
Goodwill
impairment
|
|
|
—
|
|
|
149,217
|
|
|
347,283
|
Changes in fair value
of derivative instruments
|
|
|
109,536
|
|
|
18,074
|
|
|
59,750
|
Deferred income tax
expense/(recovery)
|
|
|
98,755
|
|
|
(188,260)
|
|
|
61,650
|
Foreign exchange
(gain)/loss on debt and working capital
|
|
|
(8,055)
|
|
|
1,363
|
|
|
(21,899)
|
Share-based
compensation and general and administrative
|
|
|
13,424
|
|
|
9,508
|
|
|
17,356
|
Other
expense/(income)
|
|
|
(4,594)
|
|
|
—
|
|
|
—
|
Amortization of debt
issuance costs
|
|
|
1,093
|
|
|
—
|
|
|
—
|
Translation of U.S.
dollar cash held in parent company
|
|
|
(2,330)
|
|
|
(902)
|
|
|
6,825
|
Other income
reclassified to Investing Activities
|
|
|
(4,593)
|
|
|
—
|
|
|
—
|
Asset retirement
obligation settlements
|
|
|
(12,951)
|
|
|
(13,275)
|
|
|
(12,646)
|
Changes in non-cash
operating working capital
|
|
|
(94,643)
|
|
|
83,669
|
|
|
(3,197)
|
Cash flow from/(used
in) operating activities
|
|
|
604,839
|
|
|
335,884
|
|
|
519,768
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
|
|
|
|
|
|
|
Proceeds from bank
term loan/bank credit facility
|
|
|
400,000
|
|
|
—
|
|
|
—
|
Debt issuance
costs
|
|
|
(4,621)
|
|
|
—
|
|
|
—
|
Repayment of senior
notes
|
|
|
(81,600)
|
|
|
(81,600)
|
|
|
(44,444)
|
Proceeds from the
issuance of shares
|
|
|
98,339
|
|
|
—
|
|
|
—
|
Purchase of common
shares under Normal Course Issuer Bid
|
|
|
(123,182)
|
|
|
(1,807)
|
|
|
(134,285)
|
Share-based
compensation – tax withholdings settled in cash
|
|
|
(3,551)
|
|
|
(5,567)
|
|
|
(3,705)
|
Dividends
|
|
|
(32,284)
|
|
|
(19,897)
|
|
|
(21,003)
|
Cash flow from/(used
in) financing activities
|
|
|
253,101
|
|
|
(108,871)
|
|
|
(203,437)
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities
|
|
|
|
|
|
|
|
|
|
Capital and office
expenditures
|
|
|
(271,131)
|
|
|
(248,990)
|
|
|
(454,521)
|
Bruin
acquisition
|
|
|
(420,249)
|
|
|
—
|
|
|
—
|
Dunn County
acquisition
|
|
|
(305,076)
|
|
|
—
|
|
|
—
|
Property and land
acquisitions
|
|
|
(9,846)
|
|
|
(7,491)
|
|
|
(18,409)
|
Property
divestments
|
|
|
108,193
|
|
|
4,456
|
|
|
7,210
|
Other
expense/(income)
|
|
|
4,593
|
|
|
—
|
|
|
—
|
Cash flow from/(used
in) investing activities
|
|
|
(893,516)
|
|
|
(252,025)
|
|
|
(465,720)
|
Effect of exchange
rate changes on cash and cash equivalents
|
|
|
6,979
|
|
|
(1,786)
|
|
|
(295)
|
Change in cash and
cash equivalents
|
|
|
(28,597)
|
|
|
(26,798)
|
|
|
(149,684)
|
Cash and cash
equivalents, beginning of year
|
|
|
89,945
|
|
|
116,743
|
|
|
266,427
|
Cash and cash
equivalents, end of year
|
|
$
|
61,348
|
|
$
|
89,945
|
|
$
|
116,743
|
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. Previously, the Company presented production
volumes on a "company interest" basis, which was calculated as its
working interest share before deduction of royalties plus the
Company's royalty interests. With these changes, production volumes
presented by the Company on a "net" basis are expected to be lower
than those presented historically.
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, 2021 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.
Enerplus' oil and gas reserves statement for the year ended
December 31, 2021, 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, 2021 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 2022 average
production volumes, timing thereof and the anticipated production
mix; the proportion of our anticipated oil and gas production that
is hedged; 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 2022 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;
execution of our remaining NCIB authorization and the anticipated
timing thereof; expected reinvestment rates; capital spending
levels and allocations in 2022 and impact thereof on our production
levels and land holdings; our ESG initiatives, including GHG
emissions intensity, freshwater use reduction and health and safety
targets for 2022 and in the future; our anticipated progress
towards our ESG initiatives, including timing 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; our future acquisitions and dispositions, including
the divestment process for our Canadian assets in 2022 and the
completion and timing thereof; and renewal of our NCIB and timing
thereof.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: 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 commodity prices, differentials and
cost assumptions; expectations regarding inflation; the general
continuance of current or, where applicable, assumed industry
conditions; 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; 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 2022 guidance contained in this
news release is based on the following: a WTI price of $75.00/bbl, a NYMEX price of $4.00/Mcf, a Bakken crude oil price differential
of $(0.50)/bbl below WTI, a Marcellus
natural gas price differential of $(0.75)/Mcf below NYMEX and a CDN/USD exchange
rate of 0.79. 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:
decreases in commodity prices or volatility in commodity prices;
changes in realized prices of Enerplus' products; changes in the
demand for or supply of our products; 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 facility and outstanding senior
notes; inaccurate estimation of our oil and gas reserve and
contingent resource volumes; limited, unfavourable or a lack of
access to capital markets; increased costs; a lack of adequate
insurance coverage; the impact of competitors, reliance on industry
partners and third party service providers; failure to realize the
anticipated benefits of the divestment of the Sleeping Giant and
Russian Creek interests in the Williston Basin; and certain other risks
detailed from time to time in our public disclosure documents
(including, without limitation, those risks identified in our AIF
and Form 40-F as at December 31,
2021).
The purpose of our adjusted funds flow sensitivity is to
assist readers in understanding our expected and targeted financial
results, and this information may not be appropriate for other
purposes. The forward-looking information contained in this 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 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.
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
|
2019
|
Cash flow
from/(used in) operating activities
|
|
$
|
604.8
|
|
$
|
335.9
|
|
$
|
519.8
|
Asset retirement
obligation settlements
|
|
|
13.0
|
|
|
13.3
|
|
|
12.6
|
Changes in non-cash
operating working capital
|
|
|
94.6
|
|
|
(83.7)
|
|
|
3.2
|
Adjusted funds
flow
|
|
$
|
712.4
|
|
$
|
265.5
|
|
$
|
535.6
|
"Adjusted net income" 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). The
calculation follows:
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
|
2019
|
Net
income/(loss)
|
|
$
|
234.4
|
|
$
|
(693.4)
|
|
$
|
(204.4)
|
Unrealized derivative
instrument (gain)/loss
|
|
|
109.5
|
|
|
18.1
|
|
|
59.7
|
Asset
impairment
|
|
|
3.4
|
|
|
751.7
|
|
|
—
|
Unrealized foreign
exchange (gain)/loss
|
|
|
(8.1)
|
|
|
1.4
|
|
|
(21.9)
|
Tax effect on above
items
|
|
|
(24.9)
|
|
|
(201.0)
|
|
|
(13.5)
|
Other income related
to investing activities
|
|
|
(4.6)
|
|
|
—
|
|
|
—
|
Goodwill
impairment
|
|
|
—
|
|
|
149.2
|
|
|
347.3
|
Income tax rate
adjustment on deferred taxes
|
|
|
6.0
|
|
|
—
|
|
|
17.1
|
Valuation allowance
on deferred taxes
|
|
|
—
|
|
|
(11.5)
|
|
|
—
|
Adjusted net
income
|
|
$
|
315.7
|
|
$
|
14.5
|
|
$
|
184.3
|
"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. There is
no directly comparable related GAAP equivalent for this measure.
Adjusted funds flow is reconciled above.
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
|
2019
|
Adjusted funds
flow
|
|
$
|
712.4
|
|
$
|
265.5
|
|
$
|
535.6
|
Capital
spending
|
|
|
(302.3)
|
|
|
(217.2)
|
|
|
(465.9)
|
Free cash
flow
|
|
$
|
410.1
|
|
$
|
48.3
|
|
$
|
69.7
|
"Net debt" is calculated as current and long-term
debt associated with senior notes plus any outstanding bank credit
facility and term loan balances, minus cash and cash equivalents.
The calculation follows:
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
Current portion of
long-term debt
|
|
$
|
100.6
|
|
$
|
81.6
|
Long-term
debt
|
|
|
601.2
|
|
|
303.8
|
Less: Cash and
cash-equivalents
|
|
|
(61.4)
|
|
|
(89.9)
|
Net
debt
|
|
$
|
640.4
|
|
$
|
295.5
|
"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. The calculation
follows:
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
Net debt
|
|
$
|
640.4
|
|
|
295.5
|
Adjusted funds
flow
|
|
|
712.4
|
|
|
265.5
|
Net debt to
adjusted funds flow ratio
|
|
|
0.9x
|
|
|
1.1x
|
"Reinvestment rate" is used by Enerplus and is
useful to investors and securities analysts in analyzing the
reinvestment of capital spending by comparing the amount of our
capitals spending as compared to adjusted funds flow (as a
percentage). There is no closely related GAAP measure. The
calculation follows:
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
($ millions)
|
|
2021
|
|
2020
|
|
2019
|
Capital
spending
|
|
$
|
302.3
|
|
$
|
217.2
|
|
$
|
465.9
|
Adjusted funds
flow
|
|
|
712.4
|
|
|
265.5
|
|
|
535.6
|
Reinvestment rate
(%)
|
|
|
42%
|
|
|
82%
|
|
|
87%
|
Other Financial Measures
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.
Electronic copies of Enerplus' 2021 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