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' Third Quarter 2020
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, Nov. 6, 2020 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today reported
its third quarter 2020 operating and financial results. Cash
flow from operating activities for the third quarter was
$137.0 million and adjusted funds
flow was $83.1 million. Enerplus
reported a third quarter net loss of $112.8
million, or $0.51 per share.
The Company recognized a $256.8
million non-cash impairment on property, plant and equipment
("PP&E") as a result of the continued market volatility and low
commodity price environment. Excluding this impairment and certain
other non-cash items, Enerplus' third quarter 2020 adjusted net
income was $17.7 million, or
$0.08 per share.
HIGHLIGHTS
- Third quarter production was 91,022 BOE per day, including
liquids of 52,539 barrels per day
- 2020 production guidance was increased to 90,000 to 91,000 BOE
per day (from 88,000 to 90,000 BOE per day), including 50,500 to
51,000 barrels per day of liquids (from 49,000 to 50,000 barrels
per day) following production outperformance in North Dakota
- Adjusted funds flow of $83.1
million exceeded capital spending in the third quarter,
generating free cash flow of $47.8
million, with additional free cash flow forecast in the
fourth quarter
- 2020 capital spending guidance was reduced to $295 million (from $300
million)
- Reduced operating, general & administrative and
transportation cost guidance by a combined $0.45 per BOE
- Maintained low financial leverage; net debt to adjusted funds
flow ratio was 1.0 times at quarter-end
- Significant operational flexibility with an inventory of 26 net
operated drilled uncompleted wells expected at year-end
"We remain committed to preserving our strong financial position
during this period of heightened market uncertainty," said
Ian C. Dundas, President and Chief
Executive Officer of Enerplus. "Our third quarter results
demonstrate this commitment through our focus on reducing costs,
maintaining capital discipline and delivering strong operational
performance. Looking ahead into 2021, the strength of our balance
sheet and our advantaged operational flexibility will help us
continue to navigate volatility while positioning the business to
generate robust free cash flow in an improving oil price
environment."
THIRD QUARTER SUMMARY
Third quarter production was 91,022 BOE per day, an increase of
4% compared to the prior quarter and 15% lower compared to the same
period a year ago. Crude oil and natural gas liquids production in
the third quarter was 52,539 barrels per day, a 9% increase
compared to the prior quarter and 13% lower compared to the same
period a year ago. Previously curtailed production was fully
restored in the third quarter driving the higher
quarter-over-quarter volumes. The lower production compared to the
same period in 2019 was due to the reduction in capital activity in
2020.
Enerplus reported adjusted funds flow for the third quarter of
2020 of $83.1 million compared to
$175.3 million in the third quarter
of 2019. The decrease was primarily due to a combination of lower
commodity prices and production volumes.
The Company reported a net loss of $112.8
million in the third quarter of 2020 compared to net income
of $65.2 million from the prior year
period. The net loss was primarily due to non-cash PP&E
impairments of $256.8 million in the
third quarter of 2020 as a result of the continued market
volatility and low commodity price environment. Excluding the
impairment and certain other non-cash items, Enerplus' third
quarter 2020 adjusted net income was $17.7
million, or $0.08 per share,
compared to adjusted net income of $62
million, or $0.27 per share in
the third quarter of 2019.
Enerplus' third quarter 2020 realized Bakken oil price
differential was US$5.37 per barrel
below WTI, compared to US$3.61 per
barrel below WTI in the third quarter of 2019. Third quarter Bakken
oil differentials were impacted by uncertainty related to the
ongoing legal proceedings regarding the Dakota Access Pipeline.
The Company's realized Marcellus natural gas price differential
was US$0.72 per Mcf below NYMEX
during the third quarter of 2020 compared to US$0.44 per Mcf below NYMEX in the prior year
period. Weaker third quarter differentials were the result of
regional storage being near capacity, combined with lower demand
due to mild weather.
Enerplus' operating expenses were $7.78 per BOE during the third quarter, compared
to $7.06 per BOE during the same
period in 2019. The higher year-over-year unit operating expenses
were primarily due to lower production volumes and a higher liquids
production weighting in the third quarter of 2020.
Exploration and development capital spending totaled
$35.3 million in the third quarter.
The Company paid $6.7 million in
dividends in the quarter.
Enerplus remains in a strong financial position with significant
liquidity. At the end of the third quarter the Company had total
debt of $513.3 million, cash of
$84.5 million and was undrawn on its
US$600 million bank credit facility.
The Company's net debt to adjusted funds flow ratio was 1.0 times
at quarter-end.
Asset Activity
Williston Basin production averaged 48,765 BOE
per day (77% crude oil) during the third quarter of 2020, a
decrease of 11% compared to the same period in 2019 due to lower
capital activity, and 11% higher than the second quarter of 2020,
as previously curtailed production was restored. The Company
participated in drilling six gross non-operated wells (23% average
working interest) and brought one gross non-operated well (40%
working interest) on-stream during the third quarter.
Marcellus production averaged 184 MMcf per day during the third
quarter of 2020, a decrease of 19% compared to the same period in
2019 and 7% lower than the prior quarter due to reduced capital
activity during 2020. The Company participated in drilling 17 gross
non-operated wells (9% average working interest) and brought 15
gross non-operated wells (3% average working interest) on
production during the third quarter.
Canadian waterflood production averaged 7,726 BOE per day (95%
crude oil) during the third quarter of 2020, 16% lower than the
third quarter of 2019 due to reduced capital activity, and an
increase of 22% compared to the second quarter of 2020, as
previously curtailed production was restored. Enerplus brought ten
net producer/injector wells at Giltedge onstream during the third
quarter.
2020 UPDATED GUIDANCE
Enerplus is increasing its 2020 annual production guidance to
90,000 to 91,000 BOE per day (from 88,000 to 90,000 BOE per day),
including 50,500 to 51,000 barrels per day of liquids (from 49,000
to 50,000 barrels per day). The increase is primarily due to the
Company's 2020 North Dakota well program outperforming
expectations.
The Company is providing fourth quarter 2020 production guidance
of 84,000 to 87,000 BOE per day, including 47,000 to 49,000 barrels
per day of liquids.
Enerplus reduced its 2020 capital budget to $295 million, from $300
million, driven by strong operational execution in 2020.
Capital activity in the fourth quarter primarily relates to four
operated well completions in North
Dakota along with non-operated drilling and completion
activity in North Dakota and the
Marcellus. The Company expects to exit 2020 with an inventory of 26
net operated drilled uncompleted wells.
The Company has had continued success reducing its cost
structures in 2020. As a result, Enerplus is reducing its guidance
for operating expenses to $8.00 per
BOE (from $8.25 per BOE), cash
general and administrative expenses to $1.35 per BOE (from $1.40 per BOE) and its transportation costs to
$4.00 per BOE (from $4.15 per BOE).
Due to the weakness in Marcellus regional natural gas prices
during September and October, Enerplus is revising its 2020
Marcellus natural gas price differential outlook to US$0.60 per Mcf below NYMEX, from US$0.45 per Mcf below NYMEX.
Enerplus' guidance for its Bakken oil differential and royalty
and production tax rate remain unchanged. The Company's guidance is
summarized below.
2020
Guidance
|
|
Capital
spending
|
$295 million (from
$300 million)
|
Average annual
production
|
90,000 to 91,000
BOE/day (from 88,000 – 90,000 BOE/day)
|
Average annual crude
oil & natural gas liquids production
|
50,500 to 51,000
bbls/day (from 49,000 – 50,000 bbls/day)
|
Average fourth quarter
production
|
84,000 to 87,000
BOE/day
|
Average fourth quarter
crude oil & natural gas liquids production
|
47,000 to 49,000
bbls/day
|
Average royalty and
production tax rate
|
26%
|
Operating
expense
|
$8.00/BOE (from
$8.25/BOE)
|
Transportation
expense
|
$4.00/BOE (from
$4.15/BOE)
|
Cash G&A
expense
|
$1.35/BOE (from
$1.40/BOE)
|
|
|
2020 Full-Year
Differential/Basis Outlook (1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)(2)
|
US$(5.00)/bbl
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.60)/Mcf (from
US$(0.45)/Mcf)
|
(1)
|
Excluding
transportation costs.
|
(2)
|
Based on the
continued operation of the Dakota Access Pipeline.
|
2021 PRELIMINARY OUTLOOK
Based on the current commodity price environment, Enerplus
expects to execute a maintenance capital budget in 2021, which
would see the Company's production remain largely flat to the
midpoint of its fourth quarter 2020 guidance at approximately
86,000 BOE per day including 48,000 barrels per day of liquids.
Capital spending associated with this outlook is expected to be
approximately $300 million. This
capital spending outlook includes an allocation to drilling and
would support a similar maintenance capital and production profile
in 2022.
Enerplus expects this plan to generate free cash flow to fund
the dividend at approximately US$40
per barrel WTI and US$3.00 per Mcf
NYMEX, while offering more significant free cash flow potential in
an improving commodity price environment.
The Company will release its 2021 capital budget and operating
plan later in 2020 or in early 2021.
RISK MANAGEMENT
As of November 5, 2020, Enerplus
had an average of 21,000 barrels per day of crude
oil hedged through financial derivative contracts for the
remainder of 2020 and 10,000 barrels per day for the first half of
2021.
For natural gas, Enerplus had 40,000 Mcf per day hedged at a
fixed price of US$2.96 per Mcf for
the summer of 2021.
|
WTI Crude Oil (US$/bbl)(1)(2)
|
NYMEX Natural Gas
(US$/Mcf)
|
|
Oct 1, 2020 –
|
Jan 1, 2021
–
|
|
|
Dec
31, 2020
|
Jun 30,
2021
|
Apr 1, 2021 – Oct
31, 2021
|
Put
Spreads
|
|
|
|
Volume
(bbls/d)
|
16,000
|
—
|
—
|
Sold Puts
|
$ 46.88
|
—
|
—
|
Purchased
Puts
|
$ 57.50
|
—
|
—
|
|
|
|
|
Three Way
Collars
|
|
|
|
Volume
(bbls/d)
|
5,000
|
10,000
|
—
|
Sold Puts
|
$ 48.00
|
$ 32.00
|
—
|
Purchased
Puts
|
$ 56.25
|
$ 40.80
|
—
|
Sold Calls
|
$ 65.00
|
$ 51.43
|
—
|
|
|
|
|
Swaps
|
|
|
|
Volume (bbls/d or
Mcf/d)
|
—
|
—
|
40,000
|
Sold Swaps
|
—
|
—
|
$2.96
|
|
|
|
|
(1)
|
All of the sold puts
on the put spreads are settled annually at the end of 2020 rather
than monthly.
|
(2)
|
The total average
deferred premium spent on these hedges is US$2.04/bbl from Oct 1,
2020 to December 31, 2020 and US$0.42/bbl from January 1, 2021 to
June 30, 2021.
|
THIRD QUARTER PRODUCTION AND OPERATIONAL SUMMARY
TABLES
Average Daily Production(1)
|
Three months
ended September 30, 2020
|
|
Nine months
ended September 30, 2020
|
|
Crude Oil
(Mbbl/d)
|
Natural
Gas
Liquids
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
|
Crude Oil
(Mbbl/d)
|
Natural Gas
Liquids
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
Williston
Basin
|
37.5
|
5.8
|
33.0
|
48.8
|
|
37.7
|
4.9
|
29.7
|
47.5
|
Marcellus
|
-
|
-
|
184.3
|
30.7
|
|
-
|
-
|
198.9
|
33.2
|
Canadian
Waterfloods
|
7.3
|
-
|
2.0
|
7.7
|
|
7.0
|
0.1
|
2.0
|
7.4
|
Other(2)
|
1.2
|
0.7
|
11.6
|
3.8
|
|
1.4
|
0.7
|
12.5
|
4.2
|
Total
|
46.1
|
6.5
|
230.9
|
91.0
|
|
46.1
|
5.6
|
243.1
|
92.2
|
(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 September 30, 2020
|
|
Nine months
ended September 30, 2020
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
-
|
-
|
|
6
|
1.4
|
|
19
|
18.8
|
|
10
|
2.7
|
Marcellus
|
-
|
-
|
|
17
|
1.5
|
|
-
|
-
|
|
47
|
3.2
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
10
|
10.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
5
|
4.4
|
|
16
|
0.9
|
Total
|
-
|
-
|
|
23
|
2.9
|
|
34
|
33.2
|
|
73
|
6.8
|
(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 September 30, 2020
|
|
Nine months
ended September 30, 2020
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
-
|
-
|
|
1
|
0.4
|
|
18
|
15.8
|
|
8
|
2.2
|
Marcellus
|
-
|
-
|
|
15
|
0.4
|
|
-
|
-
|
|
35
|
1.0
|
Canadian
Waterfloods
|
10
|
10.0
|
|
-
|
-
|
|
10
|
10.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
2
|
1.8
|
|
1
|
0.0
|
Total
|
10
|
10.0
|
|
16
|
0.8
|
|
30
|
27.6
|
|
44
|
3.2
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Q3 2020 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) today to discuss these results. Details of the
conference call are as follows:
|
|
Date:
|
Friday, November 6,
2020
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
Conference
ID:
|
44159509
|
Audiocast:
|
https://produceredition.webcasts.com/starthere.jsp?ei=1382966&tp_key=bd5166311d
|
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:
|
159509 #
|
SELECTED FINANCIAL
RESULTS
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Financial (CDN$,
thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
(112,753)
|
|
$
|
65,181
|
|
$
|
(719,200)
|
|
$
|
169,423
|
Adjusted Net
Income/(Loss)(1)
|
|
|
17,705
|
|
|
61,969
|
|
|
(2,391)
|
|
|
208,793
|
Cash Flow from
Operating Activities
|
|
|
136,987
|
|
|
159,806
|
|
|
350,286
|
|
|
505,748
|
Adjusted Funds
Flow(1)
|
|
|
83,065
|
|
|
175,277
|
|
|
266,289
|
|
|
530,070
|
Dividends to
Shareholders - Declared
|
|
|
6,676
|
|
|
6,836
|
|
|
20,021
|
|
|
21,032
|
Total Debt Net of
Cash(1)
|
|
|
428,768
|
|
|
521,379
|
|
|
428,768
|
|
|
521,379
|
Capital
Spending
|
|
|
35,345
|
|
|
151,520
|
|
|
239,054
|
|
|
519,521
|
Property and Land
Acquisitions
|
|
|
2,388
|
|
|
13,344
|
|
|
8,060
|
|
|
18,280
|
Property
Divestments
|
|
|
583
|
|
|
(168)
|
|
|
6,098
|
|
|
9,899
|
Net Debt to Adjusted
Funds Flow Ratio(1)
|
|
|
1.0x
|
|
|
0.7x
|
|
|
1.0x
|
|
|
0.7x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income /(Loss) -
Basic
|
|
$
|
(0.51)
|
|
$
|
0.28
|
|
$
|
(3.23)
|
|
$
|
0.72
|
Net Income/(Loss) -
Diluted
|
|
|
(0.51)
|
|
|
0.28
|
|
|
(3.23)
|
|
|
0.71
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
|
222,548
|
|
|
228,908
|
|
|
222,487
|
|
|
234,403
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
|
222,548
|
|
|
231,529
|
|
|
222,487
|
|
|
237,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(4)
|
|
$
|
28.65
|
|
$
|
40.75
|
|
$
|
26.95
|
|
$
|
43.02
|
Royalties and
Production Taxes
|
|
|
(7.36)
|
|
|
(10.80)
|
|
|
(6.94)
|
|
|
(10.86)
|
Commodity Derivative
Instruments
|
|
|
2.36
|
|
|
0.53
|
|
|
4.21
|
|
|
0.54
|
Operating
Expenses
|
|
|
(7.78)
|
|
|
(7.06)
|
|
|
(7.86)
|
|
|
(7.83)
|
Transportation
Costs
|
|
|
(3.85)
|
|
|
(3.96)
|
|
|
(4.02)
|
|
|
(3.97)
|
Cash General and
Administrative Expenses
|
|
|
(1.40)
|
|
|
(1.19)
|
|
|
(1.33)
|
|
|
(1.32)
|
Cash Share-Based
Compensation
|
|
|
0.09
|
|
|
—
|
|
|
0.09
|
|
|
(0.02)
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(0.82)
|
|
|
(0.49)
|
|
|
(1.14)
|
|
|
(0.65)
|
Current Income Tax
Recovery
|
|
|
0.02
|
|
|
—
|
|
|
0.57
|
|
|
0.72
|
Adjusted Funds
Flow(1)
|
|
$
|
9.91
|
|
$
|
17.78
|
|
$
|
10.53
|
|
$
|
19.63
|
|
SELECTED OPERATING
RESULTS
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Average Daily
Production(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
46,082
|
|
|
55,023
|
|
|
46,098
|
|
|
48,141
|
Natural Gas Liquids
(bbls/day)
|
|
|
6,457
|
|
|
5,098
|
|
|
5,581
|
|
|
4,736
|
Natural Gas
(Mcf/day)
|
|
|
230,895
|
|
|
282,360
|
|
|
243,083
|
|
|
276,063
|
Total
(BOE/day)
|
|
|
91,022
|
|
|
107,181
|
|
|
92,193
|
|
|
98,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
58%
|
|
|
56%
|
|
|
56%
|
|
|
53%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (3)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
|
$
|
46.43
|
|
$
|
67.76
|
|
$
|
43.21
|
|
$
|
69.64
|
Natural Gas Liquids
(per bbl)
|
|
|
10.60
|
|
|
5.97
|
|
|
7.88
|
|
|
13.97
|
Natural Gas (per
Mcf)
|
|
|
1.72
|
|
|
2.13
|
|
|
1.82
|
|
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
|
3
|
|
|
17
|
|
|
40
|
|
|
47
|
(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)
|
Non-cash amounts have
been excluded.
|
(3)
|
Based on Company
interest production volumes. See "Presentation of Production
Information" below.
|
(4)
|
Before transportation
costs, royalties, and the effects of commodity derivative
instruments.
|
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
Average Benchmark
Pricing
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
WTI crude oil
(US$/bbl)
|
|
$
|
40.93
|
|
$
|
56.45
|
|
$
|
38.32
|
|
$
|
57.06
|
Brent (ICE) crude oil
(US$/bbl)
|
|
|
43.37
|
|
|
62.00
|
|
|
42.53
|
|
|
64.74
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
|
1.98
|
|
|
2.23
|
|
|
1.88
|
|
|
2.67
|
USD/CDN average
exchange rate
|
|
|
1.33
|
|
|
1.32
|
|
|
1.35
|
|
|
1.33
|
Share Trading
Summary
|
|
CDN(1) - ERF
|
|
U.S.(2) - ERF
|
For the three
months ended September 30, 2020
|
|
(CDN$)
|
|
(US$)
|
High
|
|
$
|
4.25
|
|
$
|
3.19
|
Low
|
|
$
|
2.31
|
|
$
|
1.72
|
Close
|
|
$
|
2.44
|
|
$
|
1.86
|
(1)
|
TSX and other
Canadian trading data combined.
|
(2)
|
NYSE and other
U.S. trading data combined.
|
2020 Dividends per Share
|
|
CDN$
|
|
US$(1)
|
First Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.02
|
Second Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.02
|
Third Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.02
|
Total
|
|
$
|
0.09
|
|
$
|
0.06
|
(1)
|
CDN$ dividends
converted at the relevant foreign exchange rate on the
payment date.
|
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). Enerplus
has adopted the standard of six thousand cubic feet of natural gas
to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to
BOEs. BOEs 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 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", "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: expectations regarding the duration and overall
impact of COVID-19, expected capital spending levels in 2020 and
impact thereof on our production levels and land holdings, expected
production volumes and updated 2020 and fourth quarter production
guidance as well as our free cash flow; expected operating strategy
in 2020, including the effect of Enerplus' production curtailment
on its properties, operations and financial position; 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; the results from our drilling program and the
timing of related production; oil and natural gas prices and
differentials, and our commodity risk management program in 2020;
expectations regarding our realized oil and natural gas prices;
expected operating, transportation and cash G&A costs;
expectations regarding our 2021 production and capital spending
levels required to achieve that production; potential future
non-cash PP&E impairments, as well as relevant factors that may
affect such impairment; future debt and working capital levels and
net debt to adjusted funds flow ratio and adjusted payout ratio,
financial capacity, liquidity and capital resources to fund capital
spending, and working capital requirements; expectations regarding
our ability to comply with debt covenants under our bank credit
facility and outstanding senior notes; Enerplus' costs reduction
initiatives and the expected cost savings therefrom in 2020; and
the amount of future cash dividends that we may pay to our
shareholders.
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; the continued ability to operate the Dakota Access
Pipeline and lack of court order restricting its operation; that
our development plans will achieve the expected results; that 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 commodity
price, differentials and cost assumptions; 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; 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; and the extent
of our liabilities. In addition, our expected 2020 capital
expenditures and operating strategy described in this news release
are based on the rest of the year prices and exchange rate of: a
WTI price of US$37.24/bbl, a NYMEX
price of US$2.82/Mcf, and a USD/CDN
exchange rate of 1.33. 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.
Current conditions, economic and otherwise, render assumptions,
although reasonable when made, subject to greater
uncertainty.
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 decline and/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; the legal proceedings
in connection with the Dakota Access Pipeline; 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; and certain other risks detailed
from time to time in our public disclosure documents (including,
without limitation, those risks identified in our interim MD&A,
our Annual Information Form, our Annual MD&A and Form 40-F as
at December 31, 2019).
The forward-looking information contained in this news
release speak only as of the date of this news release. Enerplus
does not undertake any obligation to publicly update or revise any
forward-looking information contained herein, except as required by
applicable laws
NON-GAAP MEASURES
In this news release, we use the terms "adjusted funds flow",
"adjusted net income", "free cash flow", "net debt to adjusted
funds flow ratio" and "total debt net of cash" as measures to
analyze financial and operating performance, leverage and
liquidity. "Adjusted funds flow" is calculated as cash flow
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, unrealized foreign exchange gain/loss, the tax effect
of these items, goodwill impairment, the impact of statutory
changes to the Company's corporate tax rate, and the valuation
allowance on our deferred income tax assets. "Free cash flow" is
calculated as adjusted funds flow minus capital spending. "Net debt
to adjusted funds flow ratio" is calculated as total debt net of
cash and cash equivalents, divided by a trailing 12 months of
adjusted funds flow. "Total debt net of cash" is calculated as
senior notes plus any outstanding bank credit facility balance,
minus cash and cash equivalents. Calculation of these terms is
described in Enerplus' MD&A under the "Non-GAAP Measures"
section.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow",
"net debt to adjusted funds flow", and "total debt net of cash" 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' Third Quarter 2020 MD&A.
Electronic copies of Enerplus Corporation's Third Quarter 2020
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.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation