All financial information contained within this
news release has been prepared in accordance with U.S. GAAP, except
as noted under "Non-GAAP Measures". This news release includes
forward-looking statements and information within the meaning of
applicable securities laws. Readers are advised to review the
"Forward-Looking Information and Statements" at the conclusion of
this news release. A full copy of Enerplus' Second Quarter 2021
Financial Statements and MD&A are available on the Company's
website at www.enerplus.com, under its SEDAR profile
at www.sedar.com and on the EDGAR website at
www.sec.gov.
CALGARY, AB,
Aug. 5, 2021 /CNW/ - Enerplus
Corporation ("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF)
today reported its second quarter 2021 operating and financial
results and an increase to its dividend. Cash flow from operating
activities for the second quarter was $136.9
million and adjusted funds flow was $184.3 million, compared to $90.6 million and $70.0
million, respectively, in the second quarter of 2020. Cash
flow from operating activities and adjusted funds flow increased
compared to the same period in 2020 due to higher production and
commodity prices during the second quarter of 2021.
HIGHLIGHTS
- Successfully closed the strategic acquisition of assets
in the Williston Basin from Hess
Corporation on April 30,
2021
- Achieved record production in the second quarter of
115,351 BOE per day, 26% higher than the prior quarter
- Adjusted funds flow was $184.3
million in the second quarter, which exceeded capital
spending of $129.9 million,
generating free cash flow of $54.4
million
- Annual average 2021 production guidance revised to
112,000 to 115,000 BOE per day, including 69,500 to 71,500 barrels
per day of liquids, reflecting higher mid-points, with no change in
2021 capital spending guidance
- Increasing return of capital to shareholders: quarterly
dividend increased 15% to $0.038 per
share; reinitiating share repurchase program
- Capital efficiencies continuing to improve: well costs in
North Dakota are tracking
US$5.7 million per well, a 25%
reduction compared to 2019
- 2021 Bakken crude oil price differential guidance
strengthened to US$2.35 per barrel
below WTI (from US$3.25)
- Estimated 2021 free cash flow of over $450 million based on current forward strip
commodity prices
- Net debt to adjusted funds flow ratio estimated to be at
or below 1.0x by year-end 2021 based on current forward strip
commodity prices
"Our second quarter results reflect the increasing scale
of our business and continued strong operational momentum," said
Ian C. Dundas, President and CEO.
"We delivered record production, capital efficiency gains along
with an increasing free cash flow profile. The 15% increase to
our quarterly dividend—our second dividend increase this year—and
resumption of our share repurchase program underscores our
commitment to providing increasing capital returns to shareholders.
While we are prioritizing debt reduction in the near term, we will
continue to evaluate returning incremental free cash flow to
shareholders and are well positioned to meaningfully enhance our
shareholder returns upon achieving our $400
million debt reduction target."
SECOND QUARTER SUMMARY
Production in the second quarter of 2021 was 115,351 BOE
per day, an increase of 32% compared to the same period a year ago,
and 26% higher than the prior quarter. Crude oil and
natural gas liquids production in the second quarter of 2021 was
71,693 barrels per day, an increase of 49% compared to the same
period a year ago, and 46% higher than the prior quarter. The
increased production compared to the same period in 2020 was due to
the contribution from the Company's Williston Basin acquisitions in 2021 and lower
production during the second quarter of 2020 due to reduced
activity and temporarily curtailed volumes in response to the low
crude oil prices.
Enerplus reported a second quarter 2021 net loss of
$59.7 million, or $0.23 per share, compared to a net loss of
$609.3 million, or $2.74 per share, in the same period in 2020 which
included non-cash impairments. The net loss recognized in the
second quarter of 2021 was primarily due to non-cash mark to market
losses related to commodity derivative instruments. Adjusted net
income for the second quarter of 2021 was $67.9 million, or $0.26 per share, compared to an adjusted net loss
of $41.2 million, or $0.19 per share, during the same period in 2020.
Adjusted net income was higher compared to the same period in 2020
due to higher commodity prices and increased
production.
Enerplus' second quarter 2021 realized Bakken oil price
differential was US$2.76 per barrel
below WTI, compared to US$4.36 per
barrel below WTI in the second quarter of 2020. Bakken crude oil
differentials improved relative to the prior year period due to
increased U.S. refinery demand and significant available pipeline
capacity in the basin.
The Company's realized Marcellus natural gas price differential
was US$0.89 per Mcf below NYMEX
during the second quarter of 2021 compared to US$0.49 per Mcf below NYMEX in the second quarter
of 2020. The weaker second quarter 2021 differential reflected
significant unplanned regional pipeline maintenance.
In the second quarter of 2021, Enerplus' operating
expenses were $8.43 per BOE, compared
to $6.84 per BOE during the same
period in 2020. Operating expenses in the second quarter of 2020
were impacted by price-related production curtailments and lower
well servicing activity.
Second quarter transportation costs were $3.45 per BOE and cash general and administrative
("G&A") expenses were $1.04 per
BOE.
Enerplus recorded a current tax expense of $4.2 million in the second quarter of 2021
related to U.S. federal taxes as a result of higher expected income
in 2021.
Exploration and development capital spending was $129.9 million in the second quarter of 2021. The
Company paid $11.0 million in
dividends in the quarter.
Enerplus closed its strategic acquisition of certain assets in
the Williston Basin from Hess
Corporation on April 30, 2021, for
total cash consideration of US$312
million, subject to customary purchase price
adjustments.
At the end of the second quarter of 2021, the Company had
total debt of $1,208.1 million and
cash on hand of $75.3 million.
Enerplus made principal repayments of US$81.6 million on its 2009 and 2012 senior notes
during the quarter.
ASSET ACTIVITY
Williston Basin
production averaged 72,390 BOE per day (73% crude oil) during the
second quarter of 2021, an increase of 64% compared to the same
period a year ago, and 53% higher than the prior quarter. During
the second quarter the Company drilled four gross operated wells
(100% working interest) and brought 23 gross operated wells on
production (83% average working interest). Enerplus continued to
drive capital efficiency improvements through faster drilling and
completions cycle times and other efficiencies. Enerplus set a
company record in the second quarter drilling a two-mile lateral
section in 48 hours (lateral spud to total depth). Total well costs
in North Dakota are now expected
to average US$5.7 million per well in
2021, a reduction of 25% compared to 2019 levels and well below the
2021 target of US$6.1
million.
Marcellus production averaged 192 MMcf per day during the
second quarter of 2021, a decrease of 3% compared to the same
period in 2020, and 6% lower than the prior quarter.
Canadian waterflood production averaged 7,240 BOE per day
(95% crude oil) during the second quarter of 2021, an increase of
14% compared to the same period in 2020, and 2% lower than the
prior quarter.
FREE CASH FLOW PRIORITIES
Enerplus expects to allocate approximately 90% of its free
cash flow, after dividends, to debt reduction. The Company is
targeting a net debt to adjusted funds flow ratio at or below 1.0x
assuming a $50 per barrel WTI oil
price environment, representing a debt reduction target of
approximately $400 million from
second quarter 2021 levels. Enerplus estimates it will achieve its
debt reduction target by mid-2022 based on current forward strip
commodity prices. The remaining approximately 10% of free cash
flow, after dividends, is expected to be allocated to incremental
capital returns to shareholders, including potential dividend
increases and share repurchases. The Company will continue to
evaluate this free cash flow allocation as it makes progress on its
debt reduction target with the expectation of increasing the
allocation of free cash flow to shareholders once its debt target
is achieved, assuming a supportive commodity price
environment.
Given the Company's significant increase in cash flow
generation following its strategic acquisitions in the first half
of 2021, Enerplus believes the business can support a higher
dividend while continuing to prioritize debt reduction. As a
result, the Board of Directors has approved a 15% increase to the
Company's quarterly dividend to $0.038 per share payable on September 15, 2021 to shareholders of record on
August 31, 2021. This is Enerplus'
second dividend increase year to date and represents a 27%
increase, on an annualized basis, from the Company's dividend level
at the start of the year.
Enerplus also received approval from its Board of
Directors to commence a Normal Course Issuer Bid ("NCIB"), subject
to approval by the Toronto Stock Exchange ("TSX"). The proposed
renewal will be for 10% of the public float (within the meaning
under the TSX rules).
FIVE-YEAR OUTLOOK UPDATE
Enerplus has updated year one (2021) of its five-year
outlook to reflect year to date commodity prices and the forward
strip for the remainder of the year. The years 2022 to 2025
continue to be based on US$50 to
US$55 per barrel WTI flat oil price
assumptions. Based on this, the Company has increased the estimated
cumulative free cash flow over this period to approximately
$1.5 to $2.0
billion.
2021 GUIDANCE UPDATE
Enerplus revised its 2021 average production guidance to
112,000 to 115,000 BOE per day, including liquids production of
69,500 to 71,500 barrels per day due to outperformance year to
date. Capital spending guidance is unchanged.
Enerplus narrowed its 2021 Bakken crude oil price
differential guidance to US$2.35 per
barrel below WTI, compared to US$3.25
per barrel below WTI previously. The improved differential guidance
is due to strong year to date pricing and additional firm capacity
on the Dakota Access Pipeline ("DAPL") secured in connection with
the pipeline's expansion. Enerplus now has approximately 10,000
barrels per day of firm transportation on DAPL.
As a result of ongoing pipeline maintenance in the
Marcellus, Enerplus widened its 2021 Marcellus natural gas price
differential to US$0.65 per Mcf below
NYMEX, compared to US$0.55 per Mcf
below NYMEX previously.
The Company expects to incur current income tax expense of
US$5 million to US$7 million in 2021.
A summary of the Company's 2021 guidance is provided
below.
2021 Guidance
Capital
spending
|
$360 to
$400 million
|
Average annual
production
|
112,000 – 115,000
BOE/day (from 111,000 – 115,000 BOE/day)
|
Average annual crude
oil and natural gas liquids production
|
69,500 – 71,500
bbls/day (from 68,500 – 71,500 bbls/day)
|
Average royalty and
production tax rate
|
26%
|
Operating
expense
|
$8.25/BOE
|
Transportation
expense
|
$3.85/BOE
|
Cash G&A
expense
|
$1.25/BOE
|
Current Income Tax
expense
|
US$5 – $7
million
|
2021 Full-Year Differential/Basis Outlook
(1)
U.S. Bakken crude oil
differential (compared to WTI crude oil)(2)
|
US$(2.35)/bbl (from
US$(3.25)/bbl)
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.65)/Mcf (from
US$(0.55)/Mcf)
|
(1)
|
Excluding
transportation costs.
|
(2)
|
Based on the
continued operation of the Dakota Access Pipeline.
|
Risk Management
Enerplus' commodity hedging positions are provided in the
table below.
Enerplus' Financial Commodity Hedging
Contracts (As at August
4, 2021)
|
|
WTI Crude Oil (1)(2)
(US$/bbl)
|
|
NYMEX Natural Gas
(US$/Mcf)
|
|
|
Jul 1, 2021 –
|
|
Jan 1, 2022 –
|
|
Jan 1, 2023 –
|
|
Nov 1, 2023 –
|
|
Jul 1, 2021 –
|
|
Nov 1, 2021 –
|
|
|
Dec 31, 2021
|
|
Dec 31, 2022
|
|
Oct 31, 2023
|
|
Dec 31, 2023
|
|
Oct 31, 2021
|
|
Mar 31, 2022
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
–
|
|
–
|
|
–
|
|
–
|
|
60,000
|
|
–
|
Swaps
|
|
–
|
|
–
|
|
–
|
|
–
|
|
$ 2.90
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
23,000
|
|
17,000
|
|
–
|
|
–
|
|
40,000
|
|
40,000
|
Sold Puts
|
|
$ 36.39
|
|
$ 40.00
|
|
–
|
|
–
|
|
$ 2.15
|
|
–
|
Purchased
Puts
|
|
$ 46.39
|
|
$ 50.00
|
|
–
|
|
–
|
|
$ 2.75
|
|
$ 3.43
|
Sold Calls
|
|
$ 56.70
|
|
$ 57.91
|
|
–
|
|
–
|
|
$ 3.25
|
|
$ 6.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedges acquired from
Bruin(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
8,465
|
|
3,828
|
|
250
|
|
–
|
|
–
|
|
–
|
Swaps
|
|
$ 42.52
|
|
$ 42.35
|
|
$ 42.10
|
|
–
|
|
–
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
–
|
|
–
|
|
2,000
|
|
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$0.84/bbl from
July 1, 2021 - December 31, 2021 and US$1.22/bbl from January 1,
2022 - December 31, 2022.
|
(2)
|
Transactions with a
common term have been aggregated and presented at weighted average
prices and volumes.
|
(3)
|
Upon closing of the
Bruin Acquisition, Bruin's outstanding hedges were recorded at a
fair value liability of $96.5 million. At June 30, 2021, the fair
value of the Bruin hedges was a liability of $100.0 million. For
the three and six months ended June 30, 2021 we recorded a realized
loss of $2.2 million and $1.7 million, respectively, on the
settlement of the Bruin hedges. In Addition, we recognized an
unrealized loss of $52.8 million and $35.4 million, respectively,
for the change in the fair value of the Bruin hedges over the same
periods. See Note 17 to the Q2 2021 Financial Statements for
further detail.
|
SECOND QUARTER PRODUCTION AND Operational summary
tables
Average Daily Production(1)
|
Three months ended June 30,
2021
|
|
Six months ended June 30, 2021
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-floods
|
Other(2)
|
Total
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-floods
|
Other(2)
|
Total
|
Tight oil
(bbl/d)
|
52,896
|
-
|
-
|
1,900
|
54,797
|
|
43,743
|
-
|
-
|
1,347
|
45,090
|
Light & medium
oil (bbl/d)
|
-
|
-
|
2,912
|
86
|
2,998
|
|
-
|
-
|
2,970
|
65
|
3,035
|
Heavy oil
(bbl/d)
|
-
|
-
|
3,983
|
25
|
4,008
|
|
-
|
-
|
4,045
|
17
|
4,063
|
Total crude oil (bbl/d)
|
52,896
|
-
|
6,895
|
2,012
|
61,803
|
|
43,743
|
-
|
7,015
|
1,429
|
52,188
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids (bbl/d)
|
9,257
|
-
|
129
|
504
|
9,890
|
|
7,634
|
-
|
76
|
535
|
8,245
|
|
|
|
|
|
|
|
|
|
|
|
|
Shale gas
(Mcf/d)
|
61,418
|
191,602
|
-
|
1,535
|
254,555
|
|
51,300
|
197,760
|
-
|
1,337
|
250,396
|
Conventional natural
gas (Mcf/d)
|
-
|
-
|
1,296
|
6,093
|
7,389
|
|
-
|
-
|
1,238
|
7,230
|
8,467
|
Total natural gas (Mcf/d)
|
61,418
|
191,602
|
1,296
|
7,628
|
261,945
|
|
51,300
|
197,760
|
1,238
|
8,566
|
258,863
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (BOE/d)
|
72,390
|
31,934
|
7,240
|
3,786
|
115,351
|
|
59,928
|
32,960
|
7,297
|
3,392
|
103,576
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Summary of Wells
Drilled(1)
|
Three months ended June 30,
2021
|
|
Six months ended June 30, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
4
|
4.0
|
|
-
|
-
|
|
4
|
4.0
|
|
-
|
-
|
Marcellus
|
-
|
-
|
|
14
|
0.6
|
|
-
|
-
|
|
28
|
0.8
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
2
|
0.3
|
Total
|
4
|
4.0
|
|
14
|
0.6
|
|
4
|
4.0
|
|
30
|
1.1
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Summary of Wells Brought
On-Stream(1)
|
Three months ended
June 30, 2021
|
|
Six months ended
June 30, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
23
|
19.1
|
|
1
|
0.4
|
|
26
|
22.1
|
|
1
|
0.4
|
Marcellus
|
-
|
-
|
|
20
|
1.4
|
|
-
|
-
|
|
36
|
1.8
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
3
|
2.6
|
|
2
|
0.3
|
Total
|
23
|
19.1
|
|
21
|
1.8
|
|
29
|
24.7
|
|
39
|
2.5
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Q2 2021 Conference Call Details
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM
ET) on Friday, August 6, 2021
to discuss these results. Details of the conference call are as
follows:
Date:
|
Friday, August 6,
2021
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
Conference
ID:
|
07577276
|
Audiocast:
|
https://produceredition.webcasts.com/starthere.jsp?ei=1470850&tp_key=75a2e3927a
|
To ensure timely participation in the
conference call, callers are encouraged to dial in 15 minutes prior
to the start time to register for the event. A telephone replay
will be available for 30 days following the conference call and can
be accessed at the following numbers:
Replay
Dial-In:
|
1-888-390-0541 (Toll
Free)
|
Replay
Passcode:
|
577276 #
|
SELECTED FINANCIAL RESULTS
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Financial (CDN$, thousands, except
ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
(59,664)
|
|
$
|
(609,323)
|
|
$
|
(44,967)
|
|
$
|
(606,447)
|
Adjusted Net
Income/(Loss)(1)
|
|
|
67,932
|
|
|
(41,185)
|
|
|
124,183
|
|
|
(20,095)
|
Cash Flow from
Operating Activities
|
|
|
136,902
|
|
|
90,560
|
|
|
174,141
|
|
|
213,299
|
Adjusted Funds
Flow(1)
|
|
|
184,320
|
|
|
69,997
|
|
|
312,435
|
|
|
183,224
|
Dividends to
Shareholders - Declared
|
|
|
11,040
|
|
|
6,675
|
|
|
18,405
|
|
|
13,345
|
Total Debt Net of
Cash(1)
|
|
|
1,132,841
|
|
|
518,094
|
|
|
1,132,841
|
|
|
518,094
|
Capital
Spending
|
|
|
129,903
|
|
|
40,084
|
|
|
195,434
|
|
|
203,709
|
Property and Land
Acquisitions
|
|
|
408,764
|
|
|
3,416
|
|
|
1,037,332
|
|
|
5,672
|
Property
Divestments
|
|
|
(17)
|
|
|
(63)
|
|
|
4,978
|
|
|
5,515
|
Net Debt to Adjusted
Funds Flow Ratio(1)(2)
|
|
|
2.3x
|
|
|
1.0x
|
|
|
2.3x
|
|
|
1.0x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per Weighted Average Shares
Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income /(Loss) -
Basic
|
|
$
|
(0.23)
|
|
$
|
(2.74)
|
|
$
|
(0.18)
|
|
$
|
(2.73)
|
Net Income/(Loss) -
Diluted
|
|
|
(0.23)
|
|
|
(2.74)
|
|
|
(0.18)
|
|
|
(2.73)
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
|
256,750
|
|
|
222,557
|
|
|
250,443
|
|
|
222,457
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
|
256,750
|
|
|
222,557
|
|
|
250,443
|
|
|
222,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial Results per
BOE(3)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil &
Natural Gas Sales(5)
|
|
$
|
48.60
|
|
$
|
19.53
|
|
$
|
46.38
|
|
$
|
26.11
|
Royalties and
Production Taxes
|
|
|
(12.58)
|
|
|
(5.15)
|
|
|
(11.74)
|
|
|
(6.74)
|
Commodity Derivative
Instruments
|
|
|
(3.53)
|
|
|
6.73
|
|
|
(3.02)
|
|
|
5.12
|
Operating
Expenses
|
|
|
(8.43)
|
|
|
(6.84)
|
|
|
(8.16)
|
|
|
(7.90)
|
Transportation
Costs
|
|
|
(3.45)
|
|
|
(4.28)
|
|
|
(3.68)
|
|
|
(4.11)
|
Cash General and
Administrative Expenses
|
|
|
(1.04)
|
|
|
(1.14)
|
|
|
(1.28)
|
|
|
(1.26)
|
Cash Share-Based
Compensation
|
|
|
(0.22)
|
|
|
(0.15)
|
|
|
(0.27)
|
|
|
0.09
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(1.39)
|
|
|
(1.69)
|
|
|
(1.34)
|
|
|
(1.29)
|
Current Income Tax
Recovery/(Expenses)
|
|
|
(0.40)
|
|
|
1.81
|
|
|
(0.22)
|
|
|
0.85
|
Adjusted Funds
Flow(1)
|
|
$
|
17.56
|
|
$
|
8.82
|
|
$
|
16.67
|
|
$
|
10.87
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
SELECTED OPERATING RESULTS
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
Average Daily
Production(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
61,803
|
|
|
43,168
|
|
|
52,187
|
|
|
46,106
|
|
Natural Gas Liquids
(bbls/day)
|
|
|
9,890
|
|
|
4,929
|
|
|
8,245
|
|
|
5,137
|
|
Natural Gas
(Mcf/day)
|
|
|
261,945
|
|
|
235,579
|
|
|
258,863
|
|
|
249,246
|
|
Total
(BOE/day)
|
|
|
115,351
|
|
|
87,360
|
|
|
103,576
|
|
|
92,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
62%
|
|
|
55%
|
|
|
58%
|
|
|
55%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling Price
(4)(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
|
$
|
76.67
|
|
$
|
30.55
|
|
$
|
72.90
|
|
$
|
41.59
|
|
Natural Gas Liquids
(per bbl)
|
|
|
22.72
|
|
|
(0.96)
|
|
|
28.06
|
|
|
6.16
|
|
Natural Gas (per
Mcf)
|
|
|
2.45
|
|
|
1.63
|
|
|
2.96
|
|
|
1.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
|
5
|
|
|
3
|
|
|
5
|
|
|
37
|
|
(1)
|
These are non–GAAP
measures that do not have any standardized meaning under the
Company's GAAP and, therefore, may not be directly comparable to
similar measures presented by other entities. See "Non–GAAP
Measures" section in the news release.
|
(2)
|
Ratio does not
include trailing adjusted funds flow from the recent Williston
Basin acquisitions.
|
(3)
|
Non-cash amounts have
been excluded.
|
(4)
|
Based on Company
interest production volumes. See "Presentation of Production
Information" below.
|
(5)
|
Before transportation
costs, royalties, and commodity derivative instruments.
|
Condensed Consolidated Balance Sheets
(CDN$ thousands) unaudited
|
|
|
June 30, 2021
|
|
December 31, 2020
|
Assets
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
|
$
|
75,278
|
|
$
|
114,455
|
Accounts
receivable
|
|
|
|
252,316
|
|
|
106,376
|
Derivative financial
assets
|
|
|
|
—
|
|
|
3,550
|
Other current
assets
|
|
|
|
7,505
|
|
|
7,137
|
|
|
|
|
335,099
|
|
|
231,518
|
Property, plant and
equipment:
|
|
|
|
|
|
|
|
Crude oil and natural
gas properties (full cost method)
|
|
|
|
1,680,329
|
|
|
575,559
|
Other capital assets,
net
|
|
|
|
18,912
|
|
|
19,524
|
Property, plant and
equipment
|
|
|
|
1,699,241
|
|
|
595,083
|
Right-of-use
assets
|
|
|
|
36,951
|
|
|
32,853
|
Deferred income tax
asset
|
|
|
|
600,257
|
|
|
607,001
|
Total Assets
|
|
|
$
|
2,671,548
|
|
$
|
1,466,455
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
$
|
379,255
|
|
$
|
251,822
|
Dividends
payable
|
|
|
|
—
|
|
|
2,225
|
Current portion of
long-term debt
|
|
|
|
98,688
|
|
|
103,836
|
Derivative financial
liabilities
|
|
|
|
225,696
|
|
|
19,261
|
Current portion of
lease liabilities
|
|
|
|
12,940
|
|
|
13,391
|
|
|
|
|
716,579
|
|
|
390,535
|
Derivative financial
liabilities
|
|
|
|
64,536
|
|
|
—
|
Long-term
debt
|
|
|
|
1,109,431
|
|
|
386,586
|
Asset retirement
obligation
|
|
|
|
160,201
|
|
|
130,208
|
Lease
liabilities
|
|
|
|
27,668
|
|
|
23,446
|
|
|
|
|
1,361,836
|
|
|
540,240
|
Total Liabilities
|
|
|
|
2,078,415
|
|
|
930,775
|
|
|
|
|
|
|
|
|
Shareholders' Equity
|
|
|
|
|
|
|
|
Share capital –
authorized unlimited common shares, no par value
Issued and
outstanding: June 30, 2021 – 257 million
shares
December 31, 2020 – 223 million shares
|
|
|
|
3,236,117
|
|
|
3,096,969
|
Paid-in
capital
|
|
|
|
36,269
|
|
|
50,604
|
Accumulated
deficit
|
|
|
|
(2,995,389)
|
|
|
(2,932,017)
|
Accumulated other
comprehensive income/(loss)
|
|
|
|
316,136
|
|
|
320,124
|
|
|
|
|
593,133
|
|
|
535,680
|
Total Liabilities & Shareholders'
Equity
|
|
|
$
|
2,671,548
|
|
$
|
1,466,455
|
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
|
|
|
Three months ended
|
|
Six months ended
|
|
|
|
June 30,
|
|
June 30,
|
(CDN$ thousands,
except per share amounts) unaudited
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural
gas sales, net of royalties
|
|
|
$
|
408,622
|
|
$
|
122,069
|
|
$
|
697,423
|
|
$
|
350,196
|
Commodity derivative
instruments gain/(loss)
|
|
|
|
(197,967)
|
|
|
(10,895)
|
|
|
(267,810)
|
|
|
120,446
|
|
|
|
|
210,655
|
|
|
111,174
|
|
|
429,613
|
|
|
470,642
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
88,459
|
|
|
54,353
|
|
|
152,981
|
|
|
133,373
|
Transportation
|
|
|
|
36,188
|
|
|
34,006
|
|
|
69,011
|
|
|
69,335
|
Production
taxes
|
|
|
|
30,502
|
|
|
7,687
|
|
|
47,954
|
|
|
23,131
|
General and
administrative
|
|
|
|
12,474
|
|
|
13,494
|
|
|
28,746
|
|
|
32,679
|
Depletion,
depreciation and accretion
|
|
|
|
93,908
|
|
|
79,885
|
|
|
140,368
|
|
|
175,077
|
Asset
impairment
|
|
|
|
—
|
|
|
426,810
|
|
|
4,300
|
|
|
426,810
|
Goodwill
impairment
|
|
|
|
—
|
|
|
202,767
|
|
|
—
|
|
|
202,767
|
Interest
|
|
|
|
9,527
|
|
|
7,051
|
|
|
16,350
|
|
|
15,962
|
Foreign exchange
(gain)/loss
|
|
|
|
6,864
|
|
|
1,493
|
|
|
6,986
|
|
|
(4,144)
|
Transaction costs and
other expense/(income)
|
|
|
|
(718)
|
|
|
6,301
|
|
|
3,806
|
|
|
6,072
|
|
|
|
|
277,204
|
|
|
833,847
|
|
|
470,502
|
|
|
1,081,062
|
Income/(Loss) before taxes
|
|
|
|
(66,549)
|
|
|
(722,673)
|
|
|
(40,889)
|
|
|
(610,420)
|
Current income tax
expense/(recovery)
|
|
|
|
4,175
|
|
|
(14,422)
|
|
|
4,175
|
|
|
(14,395)
|
Deferred income tax
expense/(recovery)
|
|
|
|
(11,060)
|
|
|
(98,928)
|
|
|
(97)
|
|
|
10,422
|
Net Income/(Loss)
|
|
|
$
|
(59,664)
|
|
$
|
(609,323)
|
|
$
|
(44,967)
|
|
$
|
(606,447)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain/(loss) on foreign currency translation
|
|
|
|
(14,345)
|
|
|
(57,284)
|
|
|
(27,212)
|
|
|
74,490
|
Foreign exchange
gain/(loss) on net investment hedge with U.S.
denominated debt, net of tax
|
|
|
|
14,702
|
|
|
19,466
|
|
|
23,224
|
|
|
(30,596)
|
Total Comprehensive
Income/(Loss)
|
|
|
$
|
(59,307)
|
|
$
|
(647,141)
|
|
$
|
(48,955)
|
|
$
|
(562,553)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(Loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$
|
(0.23)
|
|
$
|
(2.74)
|
|
$
|
(0.18)
|
|
$
|
(2.73)
|
Diluted
|
|
|
$
|
(0.23)
|
|
$
|
(2.74)
|
|
$
|
(0.18)
|
|
$
|
(2.73)
|
Condensed Consolidated Statements of Cash
Flows
|
|
|
Three months ended
|
|
Six months ended
|
|
|
|
June 30,
|
|
June 30,
|
(CDN$ thousands) unaudited
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss)
|
|
|
$
|
(59,664)
|
|
$
|
(609,323)
|
|
$
|
(44,967)
|
|
$
|
(606,447)
|
Non-cash items
add/(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and accretion
|
|
|
|
93,908
|
|
|
79,885
|
|
|
140,368
|
|
|
175,077
|
Asset
impairment
|
|
|
|
—
|
|
|
426,810
|
|
|
4,300
|
|
|
426,810
|
Goodwill
impairment
|
|
|
|
—
|
|
|
202,767
|
|
|
—
|
|
|
202,767
|
Changes in fair value
of derivative instruments
|
|
|
|
160,130
|
|
|
63,929
|
|
|
209,972
|
|
|
(32,499)
|
Deferred income tax
expense/(recovery)
|
|
|
|
(11,060)
|
|
|
(98,928)
|
|
|
(97)
|
|
|
10,422
|
Foreign exchange
(gain)/loss on debt and working capital
|
|
|
|
5,539
|
|
|
1,038
|
|
|
5,858
|
|
|
(1,377)
|
Share-based
compensation and general and administrative
|
|
|
|
(23)
|
|
|
3,428
|
|
|
990
|
|
|
11,183
|
Other
expenses/(income)
|
|
|
|
(2,353)
|
|
|
—
|
|
|
(2,353)
|
|
|
—
|
Amortization of debt
issuance costs
|
|
|
|
312
|
|
|
—
|
|
|
385
|
|
|
—
|
Translation of U.S.
dollar cash held in Canada
|
|
|
|
(2,469)
|
|
|
391
|
|
|
(2,021)
|
|
|
(2,712)
|
Asset retirement
obligation settlements
|
|
|
|
(1,359)
|
|
|
(333)
|
|
|
(8,439)
|
|
|
(11,127)
|
Changes in non-cash
operating working capital
|
|
|
|
(46,059)
|
|
|
20,896
|
|
|
(129,855)
|
|
|
41,202
|
Cash flow from/(used
in) operating activities
|
|
|
|
136,902
|
|
|
90,560
|
|
|
174,141
|
|
|
213,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank term
loan
|
|
|
|
—
|
|
|
—
|
|
|
501,286
|
|
|
—
|
Bank credit
facility
|
|
|
|
333,616
|
|
|
1,364
|
|
|
333,616
|
|
|
1,364
|
Repayment of senior
notes
|
|
|
|
(99,348)
|
|
|
(114,010)
|
|
|
(99,348)
|
|
|
(114,010)
|
Proceeds from the
issuance of shares
|
|
|
|
—
|
|
|
—
|
|
|
125,746
|
|
|
—
|
Purchase of common
shares under Normal Course Issuer Bid
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,536)
|
Share-based
compensation – cash settled (tax withholding)
|
|
|
|
—
|
|
|
—
|
|
|
(4,491)
|
|
|
(7,232)
|
Dividends
|
|
|
|
(13,608)
|
|
|
(6,676)
|
|
|
(20,627)
|
|
|
(13,337)
|
Cash flow from/(used
in) financing activities
|
|
|
|
220,660
|
|
|
(119,322)
|
|
|
836,182
|
|
|
(135,751)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and office
expenditures
|
|
|
|
(92,422)
|
|
|
(104,111)
|
|
|
(144,184)
|
|
|
(233,453)
|
Bruin
acquisition
|
|
|
|
(2,537)
|
|
|
—
|
|
|
(531,134)
|
|
|
—
|
Dunn County
acquisition
|
|
|
|
(374,613)
|
|
|
—
|
|
|
(374,613)
|
|
|
—
|
Property and land
acquisitions
|
|
|
|
(1,619)
|
|
|
(3,416)
|
|
|
(5,026)
|
|
|
(5,672)
|
Property
divestments
|
|
|
|
(17)
|
|
|
(63)
|
|
|
4,978
|
|
|
5,515
|
Cash flow from/(used
in) investing activities
|
|
|
|
(471,208)
|
|
|
(107,590)
|
|
|
(1,049,979)
|
|
|
(233,610)
|
Effect of exchange
rate changes on cash & cash equivalents
|
|
|
|
(92)
|
|
|
453
|
|
|
479
|
|
|
10,590
|
Change in cash and
cash equivalents
|
|
|
|
(113,738)
|
|
|
(135,899)
|
|
|
(39,177)
|
|
|
(145,472)
|
Cash and cash
equivalents, beginning of period
|
|
|
|
189,016
|
|
|
142,076
|
|
|
114,455
|
|
|
151,649
|
Cash and cash equivalents, end of
period
|
|
|
$
|
75,278
|
|
$
|
6,177
|
|
$
|
75,278
|
|
$
|
6,177
|
Currency and Accounting Principles
All amounts in this news release are stated in Canadian
dollars unless otherwise specified. All financial information in
this news release has been prepared and presented in accordance
with U.S. GAAP, except as noted below under "Non-GAAP
Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE"
(barrels of oil equivalent), "MBOE" (one thousand barrels of oil
equivalent), and "MMBOE" (one million barrels of oil equivalent).
Enerplus has adopted the standard of six thousand cubic feet of gas
to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to
BOEs. BOE, MBOE and MMBOE may be misleading, particularly if
used in isolation. The foregoing conversion ratios are based
on an energy equivalency conversion method primarily applicable at
the burner tip and do not represent a value equivalency at the
wellhead. Given that the value ratio based on the current price of
oil as compared to natural gas is significantly different from the
energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may
be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally
presented net of royalties and U.S. industry protocol is to present
production volumes net of royalties. Under Canadian disclosure
requirements and industry practice, oil and gas sales and
production volumes are presented on a gross basis before deduction
of royalties. All production volumes and oil and gas sales
presented herein are reported on a "company interest" basis, before
deduction of Crown and other royalties, plus Enerplus' royalty
interest. All references to "liquids" in this news release include
light and medium crude oil, heavy oil and tight oil (all together
referred to as "crude oil") and natural gas liquids on a combined
basis.
FORWARD-LOOKING INFORMATION AND
STATEMENTS
This news release contains certain forward-looking
information and forward-looking statements within the meaning of
applicable securities laws ("forward-looking information"). The use
of any of the words "expect", "anticipate", "continue", "estimate",
"guidance", "believes" and "plans" and similar expressions are
intended to identify forward-looking information. In particular,
but without limiting the foregoing, this news release contains
forward-looking information pertaining to the following:
expected benefits of the Hess asset and Bruin acquisition;
expected impact of the Hess asset and Bruin acquisitions on
Enerplus' operations and financial results, including expected free
cash flow in 2021 and beyond and year-end net debt to adjusted
funds flow ratio; anticipated impact of the Hess asset and Bruin
acquisitions on Enerplus' future costs and expenses; the renewal of
Enerplus' NCIB and terms thereof; expected capital spending levels
in 2021 and the future and the impact thereof on our production
levels and land holdings; expected production volumes and updated
2021 and future production guidance; expected operating strategy in
2021; the effect of Enerplus' participation in the DAPL expansion
on increased crude oil transportation; 2021 average production
volumes, timing thereof and the anticipated production mix; the
proportion of our anticipated oil and gas production that is hedged
and the expected effectiveness of such hedges in protecting our
adjusted funds flow in 2021 and the future; the results from our
drilling program and the timing of related production and ultimate
well recoveries; oil and natural gas prices and differentials, our
commodity risk management program in 2021 and expected hedging
gains; expectations regarding our realized oil and natural gas
prices; expected operating, transportation, cash G&A and
financing costs; expected reduction in well costs; future royalty
rates on our production and future production taxes; net debt to
adjusted funds-flow ratio, financial capacity and liquidity and
capital resources to fund capital spending, dividends and working
capital requirements; expectations regarding our ability to comply
with debt covenants under our bank credit facility, term loan and
outstanding senior notes; and expectations regarding payment of
increased dividends.
The forward-looking information contained in this news
release reflects several material factors, expectations and
assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated,
including considering the Hess asset and Bruin acquisition; that
our development plans will achieve the expected results; that a
lack of adequate infrastructure and/or low commodity price
environment will not result in curtailment of production and/or
reduced realized prices beyond our current expectations; current
and estimated commodity prices, differentials and cost assumptions;
the continued ability to operate DAPL; that our development plans
will achieve the expected results; the general continuance of
current or, where applicable, assumed industry conditions,
including expectations regarding the duration and overall impact of
COVID-19; the continuation of assumed tax, royalty and regulatory
regimes; the accuracy of the estimates of our reserve and
contingent resource volumes; the continued availability of adequate
debt and/or equity financing and adjusted funds flow to fund our
capital, operating and working capital requirements, and dividend
payments as needed; the continued availability and sufficiency of
our adjusted funds flow and availability under our bank credit
facility to fund our working capital deficiency; our ability to
comply with our debt covenants; the availability of third party
services; the extent of our liabilities; the rates used to
calculate the amount of our future abandonment
and reclamation costs and asset retirement
obligations; the availability of technology and
processes to achieve environmental targets. In addition, Enerplus'
2021 outlook contained in this news release is based on the
following rest of year prices: US$69/bbl WTI, US$3.92/Mcf NYMEX, and a USD/CDN exchange rate of
1.26. Furthermore, in addition, years 2022 to 2025 of
Enerplus' five-year outlook contained in this news release is based
on the following: a WTI price of between US$50.00/bbl and US$55.00/bbl, a NYMEX price of US$2.75/Mcf and a USD/CDN exchange rate of 1.27.
We believe the material factors, expectations and assumptions
reflected in the forward-looking information are reasonable but no
assurance can be given that these factors, expectations and
assumptions will prove to be correct.
The forward-looking information included in
this news release is not a guarantee of future
performance and should not be unduly relied upon. Such information
involves known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from
those anticipated in such forward-looking information including,
without limitation: continued instability, or
further deterioration, in global economic and market environment,
including from COVID-19; continued low
commodity price environment or further volatility in commodity
prices; changes in realized prices of Enerplus' products from those
currently anticipated; changes in the demand for or supply of our
products; failure to realize the anticipated benefits of the Hess
asset and Bruin acquisitions; unanticipated operating results,
results from our capital spending activities or production
declines; legal proceedings in connection with
DAPL; curtailment of our production due to low
realized prices or lack of adequate infrastructure; changes in tax
or environmental laws, royalty rates or other regulatory matters;
changes in our capital plans or by third party operators of our
properties; increased debt levels or debt service requirements;
inability to comply with debt covenants under our bank credit
facility and outstanding senior notes; inaccurate estimation of our
oil and gas reserve and contingent resource volumes; limited,
unfavourable or a lack of access to capital markets; increased
costs; a lack of adequate insurance coverage; the impact of
competitors; reliance on industry partners and third party service
providers; changes in law or government
programs or policies in Canada or
the United States;
and certain other risks detailed from time to time in our
public disclosure documents (including, without limitation, those
risks and contingencies described under "Risk Factors and Risk
Management" in Enerplus' 2020 MD&A and in our other public
filings).
The purpose of our estimated free cash flow disclosure
is to assist readers in understanding our expected and targeted
financial results and this information may not be appropriate for
other purposes. The forward-looking information contained in this
press release speaks only as of the date of this press release, and
we do not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances,
except as may be required pursuant to applicable
laws.
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted
funds flow", "adjusted net income", "free cash flow" "total debt
net of cash" and "net debt to adjusted funds flow ratio" measures
to analyze operating performance, leverage and
liquidity. "Adjusted funds flow" is calculated as net cash
generated from operating activities but before changes in non-cash
operating working capital and asset retirement obligation
expenditures. "Adjusted net income" is calculated as net income
adjusted for unrealized derivative instrument gain/loss, asset
impairment, goodwill impairment, gain on divestment of assets,
unrealized foreign exchange gain/loss, and the tax effect of these
items. "Free cash flow" is calculated as adjusted funds flow minus
capital spending. "Total debt net of cash" is calculated as senior
notes plus term loan plus outstanding bank credit facility balance,
minus cash and cash equivalents". "Net debt to adjusted funds
flow" is calculated as total debt net of cash, including restricted
cash, divided by adjusted funds flow.
Enerplus believes that, in addition to cash flow from
operating activities, net earnings and other measures prescribed by
U.S. GAAP, the terms "adjusted funds flow", "adjusted net income",
"free cash flow", "total debt net of cash" and "net debt to
adjusted funds flow" are useful supplemental measures as they
provide an indication of the results generated by Enerplus'
principal business activities. However, these measures are not
measures recognized by U.S. GAAP and do not have a standardized
meaning prescribed by U.S. GAAP. Therefore, these measures, as
defined by Enerplus, may not be comparable to similar measures
presented by other issuers. For reconciliation of these measures to
the most directly comparable measure calculated in accordance with
U.S. GAAP, and further information about these measures, see
disclosure under "Non-GAAP Measures" in Enerplus' 2020
MD&A.
Electronic copies of Enerplus Corporation's Second Quarter
2021 MD&A and Financial Statements, along with other public
information including investor presentations, are available on its
website at www.enerplus.com. Shareholders may, upon request,
receive a printed copy of the Company's audited financial
statements at any time. For further information, please contact
Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com.
SOURCE Enerplus Corporation