All financial information contained within this news release
has been prepared in accordance with U.S. GAAP, except as noted
under "Non-GAAP Measures". This news release includes
forward-looking statements and information within the meaning of
applicable securities laws. Readers are advised to review the
"Forward-Looking Information and Statements" at the conclusion of
this news release. A full copy of Enerplus' First Quarter 2021
Financial Statements and MD&A will be available on the
Company's website at www.enerplus.com, under its SEDAR
profile at www.sedar.com and on the EDGAR website at
www.sec.gov.
CALGARY, AB, May 6, 2021 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today
announced financial and operating results for the first quarter of
2021 and an increase to its dividend. The Company reported first
quarter 2021 cash flow from operating activities and adjusted funds
flow of $37.2 million and
$128.0 million, respectively,
compared to $122.7 million and
$113.2 million, respectively, in the
first quarter of 2020. Cash flow from operating activities
decreased from the prior year period primarily due to changes in
working capital. Adjusted funds flow increased from the prior
year period primarily due to improved realized commodity prices
during the first quarter of 2021.
HIGHLIGHTS
- Adjusted funds flow was $128.0
million in the first quarter, which exceeded capital
spending of $65.5 million, generating
free cash flow of $62.5 million
- Delivered first quarter production of 91,671 BOE per day,
including liquids of 49,046 barrels per day
- Completed two accretive acquisitions in the Williston Basin year to date, increasing
Enerplus' acreage position in North
Dakota by over four times to 296,000 net acres and extending
its high-return development inventory
- Expect to deliver a 20% total well cost reduction in
North Dakota in 2021 compared to
2019 through continued technology application and innovation
- Maintaining a solid financial position: net debt to adjusted
funds flow ratio expected to be 1.3x or less by year-end 2021 based
on US$55 per barrel WTI (annualized
for 2021 acquisitions); current undrawn capacity on bank credit
facility of approximately US$750
million
- Increasing the dividend and transitioning to quarterly
payments: new quarterly dividend of $0.033 per share, a 10% increase from the current
monthly dividend of $0.01 per share
on an annualized basis, will be payable on June 15, 2021 to shareholders of record on
May 28, 2021. Given the April and May
dividends have already been paid or declared, the change to
quarterly payments beginning in June represents an incremental
dividend payment of $5.6 million in
the second quarter of 2021
"It has been a constructive start to the year for us, having
announced and closed two strategic acquisitions in the Bakken,"
said Ian C. Dundas, President and
CEO. "These acquisitions are expected to be highly accretive to our
per share metrics, support continued operational efficiencies and
extend our core Bakken development inventory. They are also helping
to drive a step change in the free cash flow generation of our
business. As a result, and consistent with our commitment to
sustainably growing our return of capital to shareholders, we are
increasing our dividend. As we continue integration efforts,
we remain focused on delivering safe, consistent execution under a
disciplined capital allocation framework."
FIRST QUARTER SUMMARY
Production in the first quarter of 2021 was 91,671 BOE per day,
a decrease of 7% compared to the same period a year ago, and 6%
higher than the prior quarter. Crude oil and natural gas
liquids production in the first quarter of 2021 was 49,046 barrels
per day, a decrease of 10% compared to the same period a year ago,
and approximately flat to the prior quarter. The lower production
compared to the same period in 2020 was due to the significant
reduction in capital activity in 2020 in response to the low
commodity price environment. Quarter-over-quarter production was
higher due to increased Marcellus volumes and the contribution of
approximately 6,300 BOE per day from the Company's acquisition of
Bruin which closed on March 10,
2021.
Enerplus reported first quarter 2021 net income of $14.7 million, or $0.06 per share, compared to net income of
$2.9 million, or $0.01 per share, in the same period in 2020.
Adjusted net income for the first quarter of 2021 was $56.3 million, or $0.23 per share, compared to $21.1 million, or $0.09 per share, during the same period in 2020.
Net income and adjusted net income were higher compared to the
prior year period primarily due to higher benchmark commodity
prices and stronger commodity price realizations during the first
quarter of 2021.
Enerplus' first quarter 2021 realized Bakken oil price
differential was US$3.12 per barrel
below WTI, compared to US$5.26 per
barrel below WTI in the first quarter of 2020. The improved
year-over-year Bakken differential was supported by increased
refinery demand in the first quarter of 2021, while regional
production was and continues to be lower than pre-pandemic
levels.
The Company's realized Marcellus natural gas price differential
was US$0.15 per Mcf below NYMEX
during the first quarter of 2021, compared to US$0.38 per Mcf below NYMEX in the first quarter
of 2020. Marcellus pricing is generally stronger during the first
quarter associated with an increase in seasonal demand due to the
onset of colder weather. The Company continues to expect
significant seasonality in pricing in the U.S. Northeast moving
through the rest of the year.
In the first quarter of 2021, Enerplus' operating costs were
$7.82 per BOE, transportation costs
were $3.98 per BOE and cash general
and administrative expenses were $1.59 per BOE.
Exploration and development capital spending totaled
$65.5 million in the first quarter of
2021. The Company paid $7.4 million
in dividends in the quarter.
Enerplus ended the first quarter of 2021 with total debt of
$983.2 million and cash of
$189.0 million. Subsequent to the
first quarter, the Company increased and extended its senior,
unsecured bank credit facility to US$900
million (from US$600 million)
with a maturity date extended to October 31,
2025. The Company also transitioned this facility to a
sustainability-linked credit facility ("SLL credit facility"),
incorporating sustainability-linked performance targets (see the
Company's news release dated April
29, 2021).
ASSET HIGHLIGHTS
Williston Basin production
averaged 47,327 BOE per day (73% tight oil), inclusive of
production acquired through the Bruin acquisition which closed on
March 10, 2021. This is a decrease of
4% compared to the same period a year ago, and 3% higher than the
prior quarter. The Company brought three gross operated wells (100%
working interest) on production late in the first quarter. The
Company reinitiated its drilling program in North Dakota in April and plans to continue
running one drilling rig for the rest of the year. Enerplus is
continuing to drive strong well cost efficiencies, with the average
cost for a two-mile lateral expected to decline to US$6.1 million in 2021, a 20% reduction compared
to 2019.
Marcellus production averaged 204 MMcf per day during the first
quarter of 2021, a decrease of 6% compared to the same period in
2020, and 16% higher than the prior quarter. The Company
participated in drilling 14 gross non-operated wells (1% average
working interest) and brought 16 gross non-operated wells (3%
average working interest) on production during the quarter.
Canadian waterflood production averaged 7,383 (97% oil) during
the first quarter of 2021, a decrease of 10% compared to the same
period in 2020, and 4% lower than the prior quarter.
In the DJ Basin, Enerplus brought three gross operated wells
(86% average working interest) on production during the first
quarter.
ACQUISITIONS UPDATE
Enerplus announced two strategic acquisitions in the
Williston Basin year to date,
which are expected to deliver meaningful accretion to per share
metrics, enhance the Company's free cash flow outlook, extend its
high-return drilling inventory and support further operational
efficiencies.
The Company's acquisition of Bruin for total cash consideration
of US$465 million (prior to closing
adjustments), closed on March 10,
2021. The Company's acquisition of assets from Hess
Corporation for total cash consideration of US$312 million (prior to closing adjustments),
closed on April 30, 2021. Enerplus
continues to maintain excellent liquidity and had approximately
US$750 million undrawn capacity on
its US$900 million SLL credit
facility at May 1, 2021.
DIVIDEND INCREASE; QUARTERLY PAYMENTS
Enerplus' Board of Directors approved a 10% increase to the
Company's dividend to $0.033 per
share paid quarterly, from $0.01 per
share paid monthly previously. The first increased quarterly
dividend is payable on June 15, 2021
to all shareholders of record at the close of business on
May 28, 2021. The ex-dividend date
for this payment is May 27, 2021.
2021 GUIDANCE UPDATE
Production and capital spending guidance for 2021 remains
unchanged and is summarized in the table below. Capital spending is
expected to be split relatively evenly between the first and second
half of the year. Approximately 80% of the Company's 2021 capital
budget is allocated to its North
Dakota operations where it expects to drill 21 gross (21
net) operated wells and bring 42 gross (32 net) operated wells on
production during the year. In addition to this operated activity,
the budget includes an allocation for non-operated activity in
North Dakota.
Operating expenses in 2021 are expected to average $8.25 per BOE. Unit operating expenses are
expected to increase following the first quarter due to the
Company's increased liquids production weighting from its recent
acquisitions. Enerplus' first quarter production was 54% liquids
which is expected to increase above 60% liquids for the rest of
2021.
Transportation and cash general and administrative ("G&A")
expenses in 2021 are expected to average $3.85 per BOE and $1.25 per BOE, respectively.
2021 Guidance
|
Capital
spending
|
$360 to
$400 million
|
|
Average annual
production
|
111,000 to 115,000
BOE/day
|
|
Average annual crude
oil and natural gas liquids production
|
68,500 to 71,500
bbls/day
|
|
Average royalty and
production tax rate
|
26%
|
|
Operating
expense
|
$8.25/BOE
|
|
Transportation
expense
|
$3.85/BOE
|
|
Cash G&A
expense
|
$1.25/BOE
|
2021 Full-Year Differential/Basis Outlook
(1)
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)(2)
|
US$(3.25)/bbl
|
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.55)/Mcf
|
|
(1)
|
Excluding
transportation costs.
|
|
(2)
|
Assuming the Dakota
Access Pipeline ("DAPL") continues to operate.
|
PRICE RISK MANAGEMENT
Enerplus' latest commodity hedging positions are provided in the
table below.
Enerplus' Financial Commodity Hedging
Contracts (As at May 5,
2021)
|
|
|
|
|
WTI Crude Oil
(US$/bbl)(1)(2)
|
|
NYMEX
Natural Gas
(US$/Mcf)
|
|
Apr 1,
2021 –
|
Jul 1,
2021 –
|
Jan 1,
2022 –
|
Jan 1,
2023 –
|
Nov 1,
2023 –
|
|
Apr 1, 2021 –
|
|
Jun
30, 2021
|
Dec 31,
2021
|
Dec 31,
2022
|
Oct 31,
2023
|
Dec 31,
2023
|
|
Oct
31, 2021
|
|
Swaps
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
–
|
–
|
–
|
–
|
–
|
|
60,000
|
|
Sold Swaps
|
–
|
–
|
–
|
–
|
–
|
|
$ 2.90
|
|
|
|
|
|
|
|
|
|
Three Way
Collars
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
20,000
|
23,000
|
17,000
|
–
|
–
|
|
40,000
|
|
Sold Puts
|
$ 32.00
|
$ 36.39
|
$ 40.00
|
–
|
–
|
|
$ 2.15
|
|
Purchased
Puts
|
$ 40.90
|
$ 46.39
|
$ 50.00
|
–
|
–
|
|
$ 2.75
|
|
Sold Calls
|
$ 50.72
|
$ 56.70
|
$ 57.91
|
–
|
–
|
|
$ 3.25
|
|
|
|
|
|
|
|
|
|
Hedges acquired
from Bruin (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
9,750
|
8,465
|
3,828
|
250
|
–
|
|
–
|
|
Sold Swaps
|
$ 42.16
|
$ 42.52
|
$ 42.35
|
$ 42.10
|
–
|
|
–
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
–
|
–
|
–
|
2,000
|
2,000
|
|
–
|
|
Purchased
Puts
|
–
|
–
|
–
|
$ 5.00
|
$ 5.00
|
|
–
|
|
Sold Calls
|
–
|
–
|
–
|
$ 75.00
|
$ 75.00
|
|
–
|
|
(1)
|
The total average
deferred premium spent on outstanding hedges is US$0.67/bbl from
April 1, 2021 - December 31, 2021 and US$1.22/bbl from January 1,
2022 - December 31, 2022.
|
|
(2)
|
Transactions with a
common term have been aggregated and presented at weighted average
prices and volumes.
|
|
(3)
|
Upon close of the
Bruin acquisition, Bruin's outstanding hedges were recorded at a
fair value on the balance sheet. Realized and unrealized gains and
losses on the acquired hedges are recognized in Consolidated
Statement of Income/(Loss) and the Consolidated Balance Sheets to
reflect changes in crude oil prices from the date of the close of
the Bruin acquisition. For the three months ended March 31, 2021,
Enerplus recognized an unrealized gain of $17.4 million in the
Consolidated Statement of Income/(Loss). The Bruin hedges were in a
liability position of $70.9 million at March 31, 2021.
|
Q1 2021 Conference Call Details
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM
ET) on May 7, 2021 to discuss
these results. Details of the conference call are as follows:
|
Date:
|
Friday, May 7,
2021
|
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
|
Conference
ID:
|
35089571
|
|
Audiocast:
|
https://produceredition.webcasts.com/starthere.jsp?ei=1450753&tp_key=6e8d1a2524
|
To ensure timely participation in the conference call, callers
are encouraged to join 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
|
Replay
Dial-In:
|
1-888-390-0541 (Toll
Free)
|
|
Replay
Passcode:
|
089571 #
|
Summary of Average Daily Production(1)
|
Three months ended
March 31, 2021
|
|
Williston
Basin
|
Marcellus
|
Canadian
Waterfloods
|
Other(2)
|
Total
|
|
Tight oil
(bbl/d)
|
34,489
|
-
|
-
|
787
|
35,275
|
|
Light & medium
oil (bbl/d)
|
-
|
-
|
3,040
|
32
|
3,072
|
|
Heavy oil
(bbl/d)
|
-
|
-
|
4,108
|
9
|
4,118
|
|
Total crude oil
(bbl/d)
|
34,489
|
-
|
7,149
|
828
|
42,465
|
|
|
|
|
|
|
|
Natural gas
liquids (bbl/d)
|
5,993
|
-
|
26
|
562
|
6,581
|
|
|
|
|
|
|
|
Shale gas
(Mcf/d)
|
41,069
|
203,985
|
-
|
1,136
|
246,191
|
|
Conventional natural
gas (Mcf/d)
|
-
|
-
|
1,255
|
8,303
|
9,558
|
|
Total natural gas
(Mcf/d)
|
41,069
|
203,985
|
1,255
|
9,439
|
255,748
|
|
|
|
|
|
|
|
Total production
(BOE/d)
|
47,327
|
33,998
|
7,383
|
2,964
|
91,671
|
|
(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
March 31, 2021
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Williston
Basin
|
-
|
-
|
|
-
|
-
|
|
Marcellus
|
-
|
-
|
|
14
|
0.2
|
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
Other(2)
|
-
|
-
|
|
2
|
0.3
|
|
Total
|
-
|
-
|
|
16
|
0.5
|
|
(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
March 31, 2021
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Williston
Basin
|
3
|
3.0
|
|
-
|
-
|
|
Marcellus
|
-
|
-
|
|
16
|
0.4
|
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
Other(2)
|
3
|
2.6
|
|
2
|
0.3
|
|
Total
|
6
|
5.6
|
|
18
|
0.7
|
|
(1)
|
Table may not add due
to rounding.
|
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
|
SELECTED FINANCIAL
RESULTS
|
Three months
ended
March 31,
|
|
2021
|
2020
|
|
Financial (CDN$,
thousands, except ratios)
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
14,697
|
$
|
2,876
|
|
Adjusted Net
Income/(Loss)(1)
|
|
56,251
|
|
21,089
|
|
Cash Flow from
Operating Activities
|
|
37,239
|
|
122,739
|
|
Adjusted Funds
Flow(1)
|
|
128,048
|
|
113,227
|
|
Dividends to
Shareholders - Declared
|
|
7,365
|
|
6,670
|
|
Total Debt Net of
Cash(1)
|
|
794,170
|
|
514,620
|
|
Capital
Spending
|
|
65,531
|
|
163,625
|
|
Property and Land
Acquisitions
|
|
628,568
|
|
2,256
|
|
Property
Divestments
|
|
4,995
|
|
5,578
|
|
Net Debt to Adjusted
Funds Flow Ratio(1)(2)
|
|
2.1x
|
|
0.8x
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
Net Income /(Loss) -
Basic
|
$
|
0.06
|
$
|
0.01
|
|
Net Income/(Loss) -
Diluted
|
|
0.06
|
|
0.01
|
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
244,066
|
|
222,357
|
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
246,898
|
|
223,300
|
|
|
|
|
|
|
Selected Financial
Results per BOE(3)(4)
|
|
|
|
|
|
Crude Oil &
Natural Gas Sales(5)
|
$
|
43.55
|
$
|
31.96
|
|
Royalties and
Production Taxes
|
|
(10.66)
|
|
(8.16)
|
|
Commodity Derivative
Instruments
|
|
(2.35)
|
|
3.69
|
|
Operating
Expenses
|
|
(7.82)
|
|
(8.84)
|
|
Transportation
Costs
|
|
(3.98)
|
|
(3.95)
|
|
Cash General and
Administrative Expenses
|
|
(1.59)
|
|
(1.37)
|
|
Cash Share-Based
Compensation
|
|
(0.33)
|
|
0.31
|
|
Interest, Foreign
Exchange and Other Expenses
|
|
(1.30)
|
|
(0.97)
|
|
Adjusted Funds
Flow(1)
|
$
|
15.52
|
$
|
12.67
|
|
SELECTED OPERATING
RESULTS
|
Three months
ended
March 31,
|
|
2021
|
2020
|
|
Average Daily
Production(4)
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
42,465
|
|
49,044
|
|
Natural Gas Liquids
(bbls/day)
|
|
6,581
|
|
5,346
|
|
Natural Gas
(Mcf/day)
|
|
255,749
|
|
262,913
|
|
Total
(BOE/day)
|
|
91,671
|
|
98,209
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
54%
|
|
55%
|
|
|
|
|
|
|
Average Selling
Price (4)(5)
|
|
|
|
|
|
Crude Oil (per
bbl)
|
$
|
67.34
|
$
|
51.30
|
|
Natural Gas Liquids
(per bbl)
|
|
36.17
|
|
12.72
|
|
Natural Gas (per
Mcf)
|
|
3.48
|
|
2.08
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
1
|
|
34
|
|
(1)
|
These non–GAAP
measures may not be directly comparable to similar measures
presented by other entities. See "Non–GAAP Measures" section in
this news release.
|
|
(2)
|
Ratio does not
include trailing Adjusted Funds Flow from the Bruin
Acquisition.
|
|
(3)
|
Non–cash amounts have
been excluded.
|
|
(4)
|
Based on Company
interest production volumes. See "Presentation of Production
Information" section in this news release.
|
|
(5)
|
Before transportation
costs, royalties and the effects of commodity derivative
instruments.
|
Condensed Consolidated Balance Sheets
|
(CDN$ thousands) unaudited
|
|
March 31, 2021
|
|
|
December 31, 2020
|
|
Assets
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
189,016
|
|
$
|
114,455
|
|
Accounts
receivable
|
|
208,742
|
|
|
106,376
|
|
Derivative financial
assets
|
|
4,785
|
|
|
3,550
|
|
Other current
assets
|
|
5,918
|
|
|
7,137
|
|
|
408,461
|
|
|
231,518
|
|
Property, plant and
equipment:
|
|
|
|
|
|
|
Oil and natural gas
properties (full cost method)
|
|
1,237,659
|
|
|
575,559
|
|
Other capital assets,
net
|
|
19,827
|
|
|
19,524
|
|
Property, plant and
equipment
|
|
1,257,486
|
|
|
595,083
|
|
Right-of-use
assets
|
|
32,173
|
|
|
32,853
|
|
Deferred income tax
asset
|
|
593,348
|
|
|
607,001
|
|
Total
Assets
|
$
|
2,291,468
|
|
$
|
1,466,455
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
Accounts
payable
|
$
|
290,808
|
|
$
|
251,822
|
|
Dividends
payable
|
|
2,568
|
|
|
2,225
|
|
Current portion of
long-term debt
|
|
102,506
|
|
|
103,836
|
|
Derivative financial
liabilities
|
|
118,944
|
|
|
19,261
|
|
Current portion of
lease liabilities
|
|
13,765
|
|
|
13,391
|
|
|
528,591
|
|
|
390,535
|
|
Derivative financial
liabilities
|
|
39,720
|
|
|
—
|
|
Long-term
debt
|
|
880,680
|
|
|
386,586
|
|
Asset retirement
obligation
|
|
156,734
|
|
|
130,208
|
|
Lease
liabilities
|
|
22,227
|
|
|
23,446
|
|
|
1,099,361
|
|
|
540,240
|
|
Total
Liabilities
|
|
1,627,952
|
|
|
930,775
|
|
|
|
|
|
|
|
Shareholders'
Equity
|
|
|
|
|
|
|
Share capital –
authorized unlimited common shares, no par value
Issued and
outstanding: March 31, 2021 – 257 million
shares
|
|
3,236,117
|
|
|
3,096,969
|
|
December 31, 2020 – 223 million
shares
|
|
|
|
|
|
|
Paid-in
capital
|
|
36,305
|
|
|
50,604
|
|
Accumulated
deficit
|
|
(2,924,685)
|
|
|
(2,932,017)
|
|
Accumulated other
comprehensive income/(loss)
|
|
315,779
|
|
|
320,124
|
|
|
663,516
|
|
|
535,680
|
|
Total Liabilities
& Shareholders' Equity
|
$
|
2,291,468
|
|
$
|
1,466,455
|
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
|
|
|
Three months
ended
|
|
|
|
March 31,
|
|
(CDN$ thousands,
except per share amounts) unaudited
|
|
|
2021
|
|
2020
|
|
Revenues
|
|
|
|
|
|
|
|
|
Crude oil and natural
gas sales, net of royalties
|
|
|
$
|
288,801
|
|
$
|
228,127
|
|
Commodity derivative
instruments gain/(loss)
|
|
|
|
(69,843)
|
|
|
131,341
|
|
|
|
|
218,958
|
|
|
359,468
|
|
Expenses
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
64,522
|
|
|
79,020
|
|
Transportation
|
|
|
|
32,823
|
|
|
35,329
|
|
Production
taxes
|
|
|
|
17,452
|
|
|
15,444
|
|
General and
administrative
|
|
|
|
16,272
|
|
|
19,185
|
|
Depletion,
depreciation and accretion
|
|
|
|
46,460
|
|
|
95,192
|
|
Asset
impairment
|
|
|
|
4,300
|
|
|
—
|
|
Interest
|
|
|
|
6,823
|
|
|
8,911
|
|
Foreign exchange
(gain)/loss
|
|
|
|
122
|
|
|
(5,637)
|
|
Transaction costs and
other expense/(income)
|
|
|
|
4,524
|
|
|
(229)
|
|
|
|
|
193,298
|
|
|
247,215
|
|
Income/(Loss)
before taxes
|
|
|
|
25,660
|
|
|
112,253
|
|
Current income tax
expense/(recovery)
|
|
|
|
—
|
|
|
27
|
|
Deferred income tax
expense/(recovery)
|
|
|
|
10,963
|
|
|
109,350
|
|
Net
Income/(Loss)
|
|
|
$
|
14,697
|
|
$
|
2,876
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
Unrealized
gain/(loss) on foreign currency translation
|
|
|
|
(12,867)
|
|
|
131,774
|
|
Foreign exchange
gain/(loss) on net investment hedge with U.S. denominated
debt
|
|
|
|
8,522
|
|
|
(50,062)
|
|
Total
Comprehensive Income/(Loss)
|
|
|
$
|
10,352
|
|
$
|
84,588
|
|
|
|
|
|
|
|
|
|
Net income/(Loss)
per share
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$
|
0.06
|
|
$
|
0.01
|
|
Diluted
|
|
|
$
|
0.06
|
|
$
|
0.01
|
Condensed Consolidated Statements of Cash Flows
|
Three months
ended
|
|
March 31,
|
|
(CDN$ thousands) unaudited
|
2021
|
|
2020
|
|
Operating
Activities
|
|
|
|
|
|
|
Net
income/(loss)
|
$
|
14,697
|
|
$
|
2,876
|
|
Non-cash items
add/(deduct):
|
|
|
|
|
|
|
Depletion, depreciation
and accretion
|
|
46,460
|
|
|
95,192
|
|
Asset
impairment
|
|
4,300
|
|
|
—
|
|
Changes in fair value
of derivative instruments
|
|
49,842
|
|
|
(96,428)
|
|
Deferred income tax
expense/(recovery)
|
|
10,963
|
|
|
109,350
|
|
Foreign exchange
(gain)/loss on debt and working capital
|
|
319
|
|
|
(2,415)
|
|
Share-based
compensation and general and administrative
|
|
1,842
|
|
|
7,755
|
|
Amortization of debt
issuance costs
|
|
73
|
|
|
—
|
|
Translation of U.S.
dollar cash held in Canada
|
|
(448)
|
|
|
(3,103)
|
|
Asset retirement
obligation expenditures
|
|
(7,080)
|
|
|
(10,794)
|
|
Changes in non-cash
operating working capital
|
|
(83,729)
|
|
|
20,306
|
|
Cash flow from/(used
in) operating activities
|
|
37,239
|
|
|
122,739
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
|
|
|
|
Bank term
loan
|
|
501,286
|
|
|
—
|
|
Proceeds from the
issuance of shares
|
|
125,746
|
|
|
—
|
|
Purchase of common
shares under Normal Course Issuer Bid
|
|
—
|
|
|
(2,536)
|
|
Share-based
compensation – cash settled (tax withholding)
|
|
(4,491)
|
|
|
(7,232)
|
|
Dividends
|
|
(7,019)
|
|
|
(6,661)
|
|
Cash flow from/(used
in) financing activities
|
|
615,522
|
|
|
(16,429)
|
|
|
|
|
|
|
|
Investing
Activities
|
|
|
|
|
|
|
Capital and office
expenditures
|
|
(51,762)
|
|
|
(129,342)
|
|
Bruin
acquisition
|
|
(528,597)
|
|
|
—
|
|
Property and land
acquisitions
|
|
(3,407)
|
|
|
(2,256)
|
|
Property
divestments
|
|
4,995
|
|
|
5,578
|
|
Cash flow from/(used
in) investing activities
|
|
(578,771)
|
|
|
(126,020)
|
|
Effect of exchange
rate changes on cash and cash equivalents
|
|
571
|
|
|
10,137
|
|
Change in cash and
cash equivalents
|
|
74,561
|
|
|
(9,573)
|
|
Cash and cash
equivalents, beginning of period
|
|
114,455
|
|
|
151,649
|
|
Cash and cash
equivalents, end of period
|
$
|
189,016
|
|
$
|
142,076
|
Currency and Accounting Principles
All amounts in this news release are stated in Canadian
dollars unless otherwise specified. All financial information in
this news release has been prepared and presented in accordance
with U.S. GAAP, except as noted below under "Non-GAAP
Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels
of oil equivalent), "MBOE" (one thousand barrels of oil
equivalent), and "MMBOE" (one million barrels of oil equivalent).
Enerplus has adopted the standard of six thousand cubic feet of gas
to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to
BOEs. BOE, MBOE and MMBOE may be misleading, particularly if
used in isolation. The foregoing conversion ratios are based
on an energy equivalency conversion method primarily applicable at
the burner tip and do not represent a value equivalency at the
wellhead. Given that the value ratio based on the current price of
oil as compared to natural gas is significantly different from the
energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may
be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net
of royalties and U.S. industry protocol is to present production
volumes net of royalties. Under Canadian disclosure requirements
and industry practice, oil and gas sales and production volumes are
presented on a gross basis before deduction of royalties. All
production volumes and oil and gas sales presented herein are
reported on a "company interest" basis, before deduction of Crown
and other royalties, plus Enerplus' royalty interest. All
references to "liquids" in this news release include light and
medium crude oil, heavy oil and tight oil (all together referred to
as "crude oil") and natural gas liquids on a combined
basis.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking
information and forward-looking statements within the meaning of
applicable securities laws ("forward-looking information"). The use
of any of the words "expect", "anticipate", "continue", "estimate",
"guidance", "believes" and "plans" and similar expressions are
intended to identify forward-looking information. In particular,
but without limiting the foregoing, this news release contains
forward-looking information pertaining to the following:
expected benefits of the Hess asset and Bruin acquisition;
expected impact of the Hess asset and Bruin acquisitions on
Enerplus' operations and financial results; anticipated impact of
the Hess asset and Bruin acquisitions on Enerplus' future costs and
expenses; expectations regarding the duration and overall impact of
COVID-19; expected capital spending levels in 2021 and in the
future, timing thereof; and the impact thereof on our production
levels and land holdings; expected production volumes and 2021 and
future production guidance; expected operating strategy in 2021;
2021 average production volumes, timing thereof and the anticipated
production mix; the proportion of our anticipated oil and gas
production that is hedged and the expected effectiveness of such
hedges in protecting our adjusted funds flow in 2021 and the
future; the results from our drilling program and the timing of
related production and ultimate well recoveries; oil and natural
gas prices and differentials, our commodity risk management program
in 2021 and expected hedging gains; expectations regarding our
realized oil and natural gas prices; expected operating,
transportation, cash G&A and financing costs; expected
reduction in well costs; future royalty rates on our production and
future production taxes; net debt to adjusted funds-flow ratio,
financial capacity and liquidity and capital resources to fund
capital spending, dividends and working capital requirements;
expectations regarding payment of increased dividends.
The forward-looking information contained in this news
release reflects several material factors, expectations and
assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated,
including considering the Hess asset and Bruin acquisition; that
our development plans will achieve the expected results; that a
lack of adequate infrastructure and/or low commodity price
environment will not result in curtailment of production and/or
reduced realized prices beyond our current expectations; current
and estimated commodity prices, differentials and cost assumptions;
the continued ability to operate DAPL and lack of court order
restricting its operation, that our development plans will achieve
the expected results; the general continuance of current or, where
applicable, assumed industry conditions, including expectations
regarding the duration and overall impact of COVID-19; the
continuation of assumed tax, royalty and regulatory regimes; the
accuracy of the estimates of our reserve and contingent resource
volumes; the continued availability of adequate debt and/or equity
financing and adjusted funds flow to fund our capital, operating
and working capital requirements, and dividend payments as needed;
the continued availability and sufficiency of our adjusted funds
flow and availability under our bank credit facility to fund our
working capital deficiency; our ability to comply with our debt
covenants; the availability of third party services; the extent of
our liabilities; the rates used to calculate the amount of our
future abandonment and reclamation costs and asset
retirement obligations; the availability of technology and
processes to achieve environmental targets. In addition, Enerplus'
2021 outlook contained in this news release is based on the
following: a WTI price of between US$50 and US$55.00/bbl, a NYMEX price of US$3.00/Mcf, a Bakken crude oil price
differential of US$3.25/bbl below WTI
and a USD/CDN exchange rate of 1.27. We believe the material
factors, expectations and assumptions reflected in the
forward-looking information are reasonable but no assurance can be
given that these factors, expectations and assumptions will prove
to be correct.
The forward-looking information included in this news
release is not a guarantee of future performance and should not be
unduly relied upon. Such information involves known and unknown
risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in
such forward-looking information including, without limitation:
continued instability, or further deterioration, in global
economic and market environment, including from COVID-19;
continued low commodity prices environment or further volatility
in commodity prices; changes in realized prices of Enerplus'
products; changes in the demand for or supply of our products;
failure to realize the anticipated benefits of the Hess asset and
Bruin acquisitions; unanticipated operating results, results from
our capital spending activities or production declines; the
legal proceedings in connection with DAPL; curtailment of
our production due to low realized prices or lack of adequate
infrastructure; changes in tax or environmental laws, royalty rates
or other regulatory matters; changes in our capital plans or by
third party operators of our properties; increased debt levels or
debt service requirements; inability to comply with debt covenants
under our bank credit facility and outstanding senior notes;
inaccurate estimation of our oil and gas reserve and contingent
resource volumes; limited, unfavourable or a lack of access to
capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; reliance on industry partners
and third party service providers; changes in law or
government programs or policies in Canada or the United
States; and certain other risks detailed from time to
time in our public disclosure documents (including, without
limitation, those risks and contingencies described under "Risk
Factors and Risk Management" in Enerplus' 2020 MD&A and in our
other public filings).
The forward-looking information contained in this press
release speaks only as of the date of this press release, and we do
not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances,
except as may be required pursuant to applicable laws.
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted funds
flow", "adjusted net income", "free cash flow" and "net debt to
adjusted funds flow ratio" measures to analyze operating
performance, leverage and liquidity. "Adjusted funds flow" is
calculated as net cash generated from operating activities but
before changes in non-cash operating working capital and asset
retirement obligation expenditures. "Adjusted net income" is
calculated as net income adjusted for unrealized derivative
instrument gain/loss, asset impairment, gain on divestment of
assets, unrealized foreign exchange gain/loss, and the tax effect
of these items. "Free cash flow" is calculated as adjusted funds
flow minus capital spending. "Net debt to adjusted funds flow" is
calculated as total debt net of cash, including restricted cash,
divided by adjusted funds flow.
Enerplus believes that, in addition to cash flow from
operating activities, net earnings and other measures prescribed by
U.S. GAAP, the terms "adjusted funds flow", "adjusted net income",
"free cash flow" and "net debt to adjusted funds flow" are useful
supplemental measures as they provide an indication of the results
generated by Enerplus' principal business activities. However,
these measures are not measures recognized by U.S. GAAP and do not
have a standardized meaning prescribed by U.S. GAAP. Therefore,
these measures, as defined by Enerplus, may not be comparable to
similar measures presented by other issuers. For reconciliation of
these measures to the most directly comparable measure calculated
in accordance with U.S. GAAP, and further information about these
measures, see disclosure under "Non-GAAP Measures" in Enerplus'
2020 MD&A.
Electronic copies of Enerplus Corporation's First Quarter 2021
MD&A and Financial Statements, along with other public
information including investor presentations, are available on its
website at www.enerplus.com. Shareholders may, upon request,
receive a printed copy of the Company's audited financial
statements at any time. For further information, please contact
Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com.
SOURCE Enerplus Corporation