All financial information contained within this news release
has been prepared in accordance with U.S. GAAP. This news release
includes forward-looking statements and information within the
meaning of applicable securities laws. Readers are advised to
review the "Forward-Looking Information and Statements" at the
conclusion of this news release. Readers are also referred to
"Information Regarding Reserves, Resources and Operational
Information", "Notice to U.S. Readers" and "Non-GAAP Measures" at
the end of this news release for information regarding the
presentation of the financial, reserves, contingent resources and
operational information in this news release, as well as the use of
certain financial measures that do not have standard meaning under
U.S. GAAP. A copy of Enerplus' 2020 Financial Statements and
MD&A is available on our website at www.enerplus.com, under our
profile on SEDAR at www.sedar.com and on the EDGAR website at
www.sec.gov. All amounts in this news release are stated in
Canadian dollars unless otherwise specified.
CALGARY, AB, Feb. 19, 2021 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today
reported fourth quarter 2020 cash flow from operating
activities and adjusted funds flow of $96.1
million and $91.9 million,
respectively, compared to $188.5
million and $178.9 million,
respectively, in the fourth quarter of 2019. Full year 2020
cash flow from operating activities and adjusted funds flow was
$446.4 million and $358.2 million, respectively, compared to
$694.2 million and $709.0 million, respectively, in 2019. Cash flow
from operating activities and adjusted funds flow decreased from
2019 due to lower benchmark crude oil prices and reduced production
volumes.
FULL YEAR 2020 SUMMARY AND ANNOUNCED ACQUISITION
- Generated free cash flow in 2020 – Adjusted
funds flow was $358.2 million in
2020, which exceeded capital spending of $291.4 million, generating free cash flow of
$66.8 million.
- Enhanced free cash flow outlook – Upon closing of
the recently announced acquisition of Bruin E&P HoldCo, LLC
("Bruin"), anticipated in early March
2021, Enerplus expects to see a material increase in its
free cash flow generation. Pro forma and based on a ten-month
contribution from Bruin's assets in 2021, Enerplus expects to
generate over $300 million of free
cash flow in 2021 based on US$55 per
barrel WTI crude oil and US$3.00 per
Mcf NYMEX natural gas prices.
- Maintaining a solid balance sheet – Despite the low
commodity price environment in 2020, Enerplus ended the year with a
net debt to adjusted funds flow ratio of 1.0x and was undrawn on
its US$600 million bank credit
facility. Pro forma for the announced acquisition of Bruin,
including the associated equity and term facility financings,
Enerplus expects to remain in a resilient financial position with
excellent liquidity. Enerplus estimates its year end 2021 net debt
to adjusted funds flow ratio to be approximately 1.0x based on
US$55 per barrel WTI crude oil and
US$3.00 per Mcf NYMEX natural gas
prices.
- Business resilience and safe operations –
Enerplus successfully adapted to new remote working practices
and enhanced safety measures due to the COVID-19
pandemic; achieving the best safety performance in the
Company's history based on lost time injury frequency.
- Capital efficiency improvement – Solid operational
execution delivered a step change in well cost performance in
North Dakota with a 17% reduction
(US$1.3 million per well)
year-over-year. Proved plus probable finding and development
("F&D") costs were $6.50 per BOE
in 2020, over 40% lower than the Company's prior three year
average.
- Strong performance relative to environmental targets –
Reduced 2020 greenhouse gas ("GHG") emissions intensity by more
than 20% year-over-year based on preliminary estimates (target
reduction was 10%). Reduced 2020 freshwater use per well completion
in North Dakota by 23%
year-over-year (target reduction was 15%).
"I want to thank our workforce for their efforts in the face of
a challenging 2020," said Ian C.
Dundas, President and CEO of Enerplus. "Their commitment to
keeping each other and our communities safe as we adapted to a
complicated new environment battling the spread of COVID-19 was
exceptional. It was also critical to ensuring the continuity of our
operations."
"Despite the volatile market conditions in 2020, we were able to
preserve shareholder value, maintain our strong financial footing
and position the business to deliver differentiated shareholder
returns going forward. Our announced acquisition of Bruin, expected
to close in early March 2021,
demonstrates our ongoing commitment to value creation for
shareholders, enabling us to accelerate free cash flow growth and
further support our focus on providing long term sustainable
returns."
FOURTH QUARTER 2020 SUMMARY
Enerplus delivered fourth quarter production at the high end of
its guidance ranges with total production of 86,244 BOE per day
(guidance was 84,000 to 87,000 BOE per day), including crude oil
and natural gas liquids production of 49,195 barrels per day
(guidance was 47,000 to 49,000 barrels per day). Total production
in the fourth quarter was 5% lower than the prior quarter and 20%
lower than same period in 2019. Liquids production in the
fourth quarter of 2020 was 6% lower than the prior quarter and 18%
lower than same period in 2019. The lower quarter-over-quarter
production was due to limited capital activity. The lower
production compared to the same period in 2019 was due to the
significant reduction in capital activity in North Dakota during 2020 in response to the
decline in crude oil prices, as well as lower capital activity in
the Company's Marcellus natural gas asset during 2020.
Enerplus reported a fourth quarter 2020 net loss of $204.2 million, or ($0.92) per share, compared to a net loss of
$429.1 million, or ($1.93) per share, in the fourth quarter of 2019.
The reduced net loss was primarily due to lower non-cash impairment
charges in the fourth quarter of 2020. The Company recognized a
$311.2 million non-cash property,
plant and equipment ("PP&E") impairment in the fourth quarter
of 2020 due to the low commodity price environment and the use of
12-month trailing prices to test for impairment under the
Securities and Exchange Commission ("SEC") guidelines. Excluding
the PP&E impairment and certain other non-cash or non-recurring
items, fourth quarter 2020 adjusted net income was $22.1 million, or $0.10 per share, compared to $34.4 million, or $0.15 per share, during the same period in 2019.
Adjusted net income decreased from the fourth quarter of 2019 due
to lower benchmark crude oil prices and reduced production
volumes.
Enerplus' fourth quarter 2020 Bakken crude oil price
differential was US$4.82 per barrel
below WTI, compared to US$4.40 per
barrel below WTI for the same period in 2019. The weaker
differential compared to the prior year period was due to the
narrowing of Brent-WTI differentials. Enerplus' fourth quarter
Marcellus natural gas price differential was US$1.07 per Mcf below NYMEX, compared to
US$0.63 per Mcf below NYMEX for the
same period in 2019. Regional pricing in the Marcellus was
particularly weak from September to November of 2020 due to nearly
full regional storage combined with low demand due to mild
weather.
Operating expenses in the fourth quarter of 2020 were
$8.20 per BOE, compared to
$8.05 per BOE in the same period in
2019. The increase in per unit operating expenses was due to lower
production in the fourth quarter of 2020. Cash general and
administrative ("G&A") expenses were $1.46 per BOE in the fourth quarter of 2020,
compared to $1.34 per BOE in the
prior year period. The increase in per unit G&A expenses was
also due to lower production in the fourth quarter of 2020.
Exploration and development capital spending totaled
$52.4 million in the fourth quarter
of 2020. The Company paid $6.7
million in dividends during the quarter.
Enerplus ended the fourth quarter of 2020 with total debt net of
cash of $376.0 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.
FULL YEAR 2020 SUMMARY
Enerplus delivered 2020 production at the high end of its annual
guidance ranges with total production of 90,697 BOE per day
(guidance was 90,000 to 91,000 BOE per day), including crude oil
and natural gas liquids production of 51,054 barrels per day
(guidance was 50,500 to 51,000 barrels per day). Total production
and liquids production decreased 10% and 7%, respectively, compared
to 2019. The year-over-year decrease in liquids production was due
to the temporary curtailment of crude oil production during the
second quarter and the significant reduction in capital activity in
North Dakota during 2020 in
response to the decline in crude oil prices. Natural gas production
decreased 15% year-over-year due to lower capital activity in the
Company's Marcellus natural gas asset during 2020.
Enerplus reported a full year 2020 net loss of $923.4 million, or ($4.15) per share, compared to a net loss of
$259.7 million, or ($1.12) per share, in 2019. The higher net loss
was primarily due to larger non-cash impairment charges, lower
benchmark crude oil prices and reduced production volumes in 2020.
The Company recognized non-cash impairments totaling $1,197.6 million in 2020 related to PP&E and
goodwill due to the low commodity price environment and the use of
12-month trailing prices to test for impairment under the SEC
guidelines. Excluding these impairments and certain other non-cash
or non-recurring items, full year 2020 adjusted net income was
$19.8 million, or $0.09 per share, compared to $243.2 million, or $1.05 per share, in 2019. Adjusted net income
decreased from 2020 due to lower benchmark crude oil prices and
reduced production volumes.
Enerplus' 2020 Bakken crude oil price differential was
US$4.96 per barrel below WTI,
compared to US$3.61 per barrel below
WTI in 2019. The weaker year-over-year differential was due to the
significant benchmark oil price volatility and the narrowing of
Brent-WTI differentials throughout the year. Enerplus' 2020
Marcellus natural gas price differential was US$0.65 per Mcf below NYMEX, compared to
US$0.39 per Mcf below NYMEX in 2019.
Regional pricing in the Marcellus was particularly weak from
September to November of 2020 due to nearly full regional storage
combined with low demand due to mild weather.
Operating expenses in 2020 were $7.94 per BOE, compared to $7.88 per BOE in 2019. Cash G&A expenses in
2020 were $1.35 per BOE, compared to
$1.32 per BOE in 2019.
Exploration and development capital spending totaled
$291.4 million in 2020, below the
Company's capital budget guidance of $295
million. The Company paid $26.7
million in dividends in 2020.
2020 YEAR END RESERVES SUMMARY
- Total proved plus probable ("2P") reserves were 424.4 MMBOE at
year end 2020, 4% lower than year end 2019.
- Enerplus replaced 50% of total 2020 production, adding 16.7
MMBOE of 2P reserves (including technical revisions and economic
factors). In North Dakota, the
Company replaced 69% of 2020 production, adding 11.3 MMBOE of 2P
reserves.
- Excluding economic factors, Enerplus replaced 89% of total 2020
production, adding 29.2 MMBOE of 2P reserves. In North Dakota, the Company replaced 119% of
2020 production excluding economic factors, adding 19.4 MMBOE of 2P
reserves. Economic factors are reserves revisions due to the
significant reduction in year-over-year forecast prices.
- F&D costs were $26.51 per BOE
for proved developed producing ("PDP") reserves, $6.78 per BOE for proved reserves, and
$6.50 per BOE for 2P reserves,
including future development costs ("FDC").
- Finding, development and acquisition ("FD&A") costs were
$6.97 per BOE for proved reserves and
$6.74 per BOE for 2P reserves,
including FDC.
ASSET ACTIVITY
Williston Basin production
averaged 46,127 BOE per day during the fourth quarter of 2020, 5%
lower than the prior quarter and 15% lower than the same period in
2019. Fourth quarter Williston
Basin production was comprised of 43,641 BOE per day in
North Dakota and 2,486 BOE per day
in Montana. In the fourth quarter,
the Company brought four operated wells on production (100% working
interest). No operated wells were drilled in the fourth quarter.
Full year 2020 production from the Williston Basin averaged 47,125 BOE per day, a
3% decrease year-over-year. Enerplus delivered meaningful
reductions to its well cost structures in 2020 driven by solid
planning and execution coupled with technology application. This
led to a continuing trend of improved drilling and completion cycle
times resulting in an average total well cost of US$6.3 million in 2020, approximately 17% lower
than 2019.
Marcellus shale gas production averaged 175 MMcf per day during
the fourth quarter of 2020, 5% lower than the prior quarter and 25%
lower than the same period in 2019. In the fourth quarter, the
Company participated in drilling 23 gross non-operated wells (7%
average working interest) with 19 gross non-operated wells (6%
average working interest) brought on production. Full year 2020
production averaged 193 MMcf per day, a 15% decrease
year-over-year.
Canadian waterflood production averaged 7,675 BOE per day during
the fourth quarter of 2020, approximately flat compared to the
prior quarter and 10% lower than the same period in 2019. Full year
2020 production averaged 7,469 BOE per day, a 17% decrease
year-over-year.
Summary of Average Daily Production(1)
|
Three months ended
December 31, 2020
|
|
Twelve months
ended December 31, 2020
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-
floods
|
Other(2)
|
Total
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-
floods
|
Other(2)
|
Total
|
Light & medium
oil (bbl/d)
|
-
|
-
|
3,167
|
25
|
3,192
|
|
-
|
-
|
3,233
|
43
|
3,277
|
Heavy oil
(bbl/d)
|
-
|
-
|
4,189
|
28
|
4,216
|
|
-
|
-
|
3,866
|
35
|
3,901
|
Tight oil
(bbl/d)
|
35,067
|
-
|
-
|
930
|
35,997
|
|
37,007
|
-
|
-
|
1,236
|
38,243
|
Total crude oil
(bbl/d)
|
35,067
|
-
|
7,356
|
982
|
43,405
|
|
37,007
|
-
|
7,100
|
1,314
|
45,421
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
liquids (bbl/d)
|
5,119
|
-
|
44
|
627
|
5,790
|
|
4,918
|
-
|
54
|
661
|
5,633
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional natural
gas (Mcf/d)
|
-
|
-
|
1,654
|
8,727
|
10,381
|
|
-
|
-
|
1,892
|
10,421
|
12,314
|
Shale gas
(Mcf/d)
|
35,644
|
175,346
|
-
|
922
|
211,912
|
|
31,200
|
193,002
|
-
|
1,342
|
225,543
|
Total natural gas
(Mcf/d)
|
35,644
|
175,346
|
1,654
|
9,649
|
222,293
|
|
31,200
|
193,002
|
1,892
|
11,763
|
237,857
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production
(BOE/d)
|
46,127
|
29,224
|
7,675
|
3,218
|
86,244
|
|
47,125
|
32,167
|
7,469
|
3,936
|
90,697
|
(1) Table may not add
due to rounding.
|
(2) Comprises DJ
Basin and non-core properties in Canada.
|
Summary of Wells Drilled(1)
|
Three months
ended December 31, 2020
|
|
Twelve months
ended December 31, 2020
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
-
|
-
|
|
1
|
0.4
|
|
19
|
18.8
|
|
11
|
3.0
|
Marcellus
|
-
|
-
|
|
23
|
1.6
|
|
-
|
-
|
|
70
|
4.8
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
10
|
10.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
5
|
4.4
|
|
16
|
0.9
|
Total
|
-
|
-
|
|
24
|
1.9
|
|
34
|
33.2
|
|
97
|
8.7
|
(1) Table may not add
due to rounding.
|
(2) Comprises DJ
Basin and non-core properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended December 31, 2020
|
|
Twelve months
ended December 31, 2020
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
4
|
4.0
|
|
7
|
1.6
|
|
22
|
20.0
|
|
15
|
3.9
|
Marcellus
|
-
|
-
|
|
19
|
1.2
|
|
-
|
-
|
|
54
|
2.2
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
10
|
10.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
2
|
1.8
|
|
1
|
0.0
|
Total
|
4
|
4.0
|
|
26
|
2.8
|
|
34
|
31.8
|
|
70
|
6.1
|
(1) Table may not add
due to rounding.
|
(2) Comprises DJ
Basin and non-core properties in Canada.
|
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE
Enerplus continued to make strong progress on its ESG
initiatives in 2020. Based on preliminary estimates, the Company
expects to have reduced its 2020 GHG emissions intensity by more
than 20% compared to 2019, an improvement compared to its target
reduction of 10%. The Company also reduced its 2020 freshwater use
per well completion in North
Dakota by 23% compared to 2019, an improvement compared to
its target reduction of 15%. Enerplus is finalizing its 2021
environmental targets as it works towards its longer-term goals,
including a 50% reduction in GHG emissions intensity by 2030 and a
50% reduction in freshwater use per well completion by
2025.
Enerplus is also on track to achieve its safety targets having
delivered a company record in 2020 with a lost time injury
frequency ("LTIF") of 0.08 injuries per 200,000 worker hours, a 66%
improvement from 2019. Enerplus is targeting a 25% reduction in
LTIF, on average, from 2020 to 2023, relative to its 2019 baseline
of 0.24.
BRUIN ACQUISITION AND 2021 GUIDANCE
On January 25, 2021, Enerplus
announced that it had entered into a definitive agreement to
acquire the equity interest of Bruin, a pure play Williston Basin private company, for total
cash consideration of US$465 million,
with no assumption of debt and subject to customary closing
conditions and purchase price adjustments (the "Bruin
Acquisition"). The Bruin Acquisition includes approximately 24,000
BOE per day of existing production and is expected to close in
early March 2021. In connection with
the Bruin Acquisition, Enerplus entered into a binding commitment
letter for a new three-year senior unsecured US$400 million term facility to be fully drawn
down on the closing date of the Bruin Acquisition to pay for a
portion of the purchase price. Enerplus intends to fund the
remaining portion of the purchase price with net proceeds from a
$132.3 million bought deal equity
financing, which was completed on February
3, 2021.
Assuming completion of the Bruin Acquisition and a ten-month
contribution from the Bruin assets to Enerplus' 2021 results,
Enerplus expects to deliver 2021 production of 103,500 to 108,500
BOE per day, including 63,000 to 67,000 barrels per day of liquids.
Capital spending in 2021 is expected to be $335 to $385
million.
Pro forma for the Bruin Acquisition, the Company expects to
realize a Bakken oil price differential of $3.25 per barrel below WTI in 2021 assuming the
Dakota Access Pipeline ("DAPL") continues to operate. For the
Marcellus, Enerplus expects to realize a natural gas price
differential of US$0.55 per Mcf below
NYMEX in 2021.
Detailed guidance for 2021 will be provided following closing of
the Bruin Acquisition.
PRICE RISK MANAGEMENT UPDATE
Enerplus' latest commodity hedging positions are provided in the
table below.
Enerplus' Financial Commodity Hedging
Contracts (As at February 18,
2021)
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil
(US$/bbl)(1)
|
|
NYMEX Natural
Gas
(US$/Mcf)
|
|
|
Jan 1, 2021 –
|
Apr 1,
2021-
|
Jul 1, 2021
-
|
Jan 1 ,2022
-
|
|
Mar 1, 2021
-
|
Apr 1, 2021
-
|
|
|
Mar 31,
2021
|
Jun 30,
2021
|
Dec 31,
2021
|
Dec 31,
2022
|
|
Mar 31,
2021
|
Oct 31,
2021
|
Swaps
|
|
|
|
|
|
|
|
|
Volume (bbls/d or
Mcf/d)
|
|
5,000
|
-
|
-
|
-
|
|
60,000
|
60,000
|
Sold Swaps
|
|
$ 45.55
|
-
|
-
|
-
|
|
$3.16
|
$ 2.90
|
|
|
|
|
|
|
|
|
|
Three Way
Collars
|
|
|
|
|
|
|
|
|
Volume (bbls/d or
Mcf/d)
|
|
15,000
|
20,000
|
23,000
|
17,000
|
|
-
|
40,000
|
Sold Puts
|
|
$ 32.00
|
$ 32.00
|
$ 36.39
|
$ 40.00
|
|
-
|
$ 2.15
|
Purchased
Puts
|
|
$ 40.53
|
$ 40.90
|
$ 46.39
|
$ 50.39
|
|
-
|
$ 2.75
|
Sold Calls
|
|
$ 50.29
|
$ 50.72
|
$ 56.70
|
$ 57.91
|
|
-
|
$ 3.25
|
(1)
|
The total average
deferred premium spent on these hedges is US$0.80/bbl from January
1, 2021 to December 31, 2021 and US$1.50/bbl
from January 1, 2022 to December 31, 2022.
|
Bruin's latest commodity hedging positions are provided below,
which Enerplus will assume upon close of the Bruin Acquisition.
Bruin's Financial Commodity Hedging Contracts (As
at February 18, 2021)
|
WTI Crude Oil
(US$/bbl)(1)(2)
|
|
Mar 1, 2021
-
|
Jan 1, 2022
-
|
Jan 1, 2023
-
|
Nov 1,
2023-
|
|
Dec 31,
2021
|
Dec 31,
2022
|
Oct 31,
2023
|
Dec 31,
2023
|
Swaps
|
|
|
|
|
Volume
(bbls/d)
|
9,000
|
3,900
|
250
|
-
|
Sold Swaps
|
$ 42.38
|
$ 42.38
|
$ 42.10
|
-
|
|
|
|
|
|
Collars
|
|
|
|
|
Volume
(bbls/d)
|
-
|
-
|
2,000
|
2,000
|
Purchased
Puts
|
-
|
-
|
$
5.00
|
$
5.00
|
Sold Calls
|
-
|
-
|
$ 75.00
|
$ 75.00
|
(1)
|
Transactions with a
common term have been aggregated and presented at weighted
average prices and volumes.
|
(2)
|
Upon close of the
Bruin Acquisition, these hedges will be recorded at fair value
on
the Consolidated Balance Sheets. Realized and unrealized gains and
losses on the
acquired hedges will be recorded in the Consolidated Statement of
Income/(Loss)
and the Consolidated Balance Sheets, respectively, to reflect
changes in WTI prices
from the date of the close of the Bruin Acquisition.
|
SUMMARY FINANCIAL AND OPERATING RESULTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED FINANCIAL RESULTS
|
December 31,
|
|
December 31,
|
|
|
2020
|
|
2019
|
|
|
2020
|
|
2019
|
Financial
(CDN$, thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
(204,167)
|
|
$
|
(429,143)
|
|
|
$
|
(923,367)
|
|
$
|
(259,720)
|
Adjusted Net
Income(1)
|
|
|
22,149
|
|
|
34,365
|
|
|
|
19,758
|
|
|
243,160
|
Cash Flow from
Operating Activities
|
|
|
96,079
|
|
|
188,492
|
|
|
|
446,365
|
|
|
694,240
|
Adjusted Funds
Flow(1)
|
|
|
91,871
|
|
|
178,922
|
|
|
|
358,160
|
|
|
708,992
|
Dividends to
Shareholders - Declared
|
|
|
6,677
|
|
|
6,656
|
|
|
|
26,698
|
|
|
27,688
|
Total Debt Net of
Cash(1)
|
|
|
375,967
|
|
|
454,984
|
|
|
|
375,967
|
|
|
454,984
|
Capital
Spending
|
|
|
52,414
|
|
|
99,389
|
|
|
|
291,468
|
|
|
618,910
|
Property and Land
Acquisitions
|
|
|
2,061
|
|
|
6,126
|
|
|
|
10,121
|
|
|
24,406
|
Property
Divestments
|
|
|
47
|
|
|
(316)
|
|
|
|
6,145
|
|
|
9,583
|
Net Debt to Adjusted
Funds Flow Ratio(1)
|
|
|
1.0x
|
|
|
0.6x
|
|
|
|
1.0x
|
|
|
0.6x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) -
Basic
|
|
$
|
(0.92)
|
|
$
|
(1.93)
|
|
|
$
|
(4.15)
|
|
$
|
(1.12)
|
Net Income/(Loss) -
Diluted
|
|
|
(0.92)
|
|
|
(1.93)
|
|
|
|
(4.15)
|
|
|
(1.12)
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
|
222,548
|
|
|
222,227
|
|
|
|
222,503
|
|
|
231,334
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
|
222,548
|
|
|
222,227
|
|
|
|
222,503
|
|
|
231,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil &
Natural Gas Sales(4)
|
|
$
|
30.60
|
|
$
|
41.64
|
|
|
$
|
27.82
|
|
$
|
42.65
|
Royalties and
Production Taxes
|
|
|
(7.67)
|
|
|
(10.93)
|
|
|
|
(7.12)
|
|
|
(10.88)
|
Commodity Derivative
Instruments
|
|
|
3.12
|
|
|
0.07
|
|
|
|
3.95
|
|
|
0.42
|
Operating
Expenses
|
|
|
(8.20)
|
|
|
(8.05)
|
|
|
|
(7.94)
|
|
|
(7.88)
|
Transportation
Costs
|
|
|
(3.89)
|
|
|
(3.82)
|
|
|
|
(3.99)
|
|
|
(3.93)
|
General and
Administrative Expenses
|
|
|
(1.46)
|
|
|
(1.34)
|
|
|
|
(1.35)
|
|
|
(1.32)
|
Cash Share-Based
Compensation
|
|
|
(0.11)
|
|
|
0.01
|
|
|
|
0.04
|
|
|
(0.02)
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(0.81)
|
|
|
(0.89)
|
|
|
|
(1.06)
|
|
|
(0.72)
|
Current Income Tax
Recovery
|
|
|
—
|
|
|
1.41
|
|
|
|
0.44
|
|
|
0.91
|
Adjusted Funds
Flow(1)
|
|
$
|
11.58
|
|
$
|
18.10
|
|
|
$
|
10.79
|
|
$
|
19.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED OPERATING RESULTS
|
December 31,
|
|
December 31,
|
|
|
2020
|
|
2019
|
|
|
2020
|
|
2019
|
Average Daily
Production(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
43,405
|
|
|
54,344
|
|
|
|
45,421
|
|
|
49,704
|
Natural Gas Liquids
(bbls/day)
|
|
|
5,790
|
|
|
5,502
|
|
|
|
5,633
|
|
|
4,929
|
Natural Gas
(Mcf/day)
|
|
|
222,293
|
|
|
285,537
|
|
|
|
237,857
|
|
|
278,451
|
Total
(BOE/day)
|
|
|
86,244
|
|
|
107,436
|
|
|
|
90,697
|
|
|
101,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
57%
|
|
|
56%
|
|
|
|
56%
|
|
|
54%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(3)(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
|
$
|
47.95
|
|
$
|
67.23
|
|
|
$
|
44.35
|
|
$
|
68.98
|
Natural Gas Liquids
(per bbl)
|
|
|
17.19
|
|
|
18.28
|
|
|
|
10.29
|
|
|
15.19
|
Natural Gas
(per Mcf)
|
|
|
2.04
|
|
|
2.50
|
|
|
|
1.87
|
|
|
2.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
|
2
|
|
|
9
|
|
|
|
42
|
|
|
56
|
(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 "Basis of Presentation" section in
this news release.
|
(4)
|
Before transportation
costs, royalties and commodity derivative instruments.
|
INDEPENDENT RESERVES EVALUATION
All of the Company's reserves, including its U.S. reserves, have
been evaluated in accordance with NI 51-101. Independent reserves
evaluations have been conducted on properties comprising
approximately 98% of the net present value (discounted at 10%,
before tax, using January 1, 2021
forecast prices and costs described below) of the Company's total
2P reserves.
McDaniel & Associates Consultants Ltd. ("McDaniel"), an
independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties
which comprise approximately 86% of the net present value
(discounted at 10%, before tax, using the average commodity price
forecasts and inflation rates of McDaniel, GLJ Petroleum
Consultants ("GLJ") and Sproule Associates Limited ("Sproule") as
of January 1, 2021) of the Company's
2P reserves located in Canada and
all of the reserves associated with the Company's properties
located in North Dakota,
Montana and Colorado. The Company has evaluated the
remaining 14% of the net present value of its Canadian properties
using similar evaluation parameters, including the same forecast
price and inflation rate assumptions utilized by McDaniel. McDaniel
has reviewed the Company's internal evaluation of these properties.
Netherland, Sewell & Associates ("NSAI"), independent petroleum
consultants based in Dallas,
Texas, has evaluated all of the Company's reserves
associated with the Company's properties in Pennsylvania. For consistency in the Company's
reserves reporting, NSAI also used the average commodity price
forecasts and inflation rates of McDaniel, GLJ and Sproule as of
January 1, 2021 to prepare its
report.
The following information sets out Enerplus' gross and net crude
oil, NGLs and natural gas reserves volumes and the
estimated net present values of future net revenues
associated with such reserves as at December
31, 2020 using forecast price and cost cases, together with
certain information, estimates and assumptions associated with such
reserves estimates. Under different price scenarios, these reserves
could vary as a change in price can affect the economic limit
associated with a property. It should be noted that tables may not
add due to rounding. The following information does not give effect
to the Bruin Acquisition.
Reserves Summary
Reserves
Summary
|
Light &
Medium
Oil
(Mbbls)
|
Heavy Oil
(Mbbls)
|
Tight
Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Gross
|
|
|
|
|
|
|
|
|
Proved
producing
|
5,884
|
15,052
|
51,508
|
72,444
|
8,123
|
17,279
|
568,258
|
178,156
|
Proved developed
non-producing
|
93
|
-
|
2,970
|
3,063
|
326
|
-
|
3,918
|
4,043
|
Proved
undeveloped
|
660
|
1,893
|
51,708
|
54,261
|
6,451
|
74
|
357,370
|
120,286
|
Total
proved
|
6,637
|
16,946
|
106,186
|
129,769
|
14,900
|
17,353
|
929,546
|
302,485
|
Total
probable
|
2,383
|
5,309
|
63,941
|
71,633
|
8,602
|
5,811
|
244,388
|
121,934
|
Proved plus
Probable
|
9,020
|
22,254
|
170,127
|
201,402
|
23,501
|
23,164
|
1,173,934
|
424,419
|
Net
|
|
|
|
|
|
|
|
|
Proved
producing
|
4,894
|
13,076
|
41,481
|
59,451
|
6,629
|
17,945
|
456,831
|
145,209
|
Proved developed
non-producing
|
77
|
-
|
2,397
|
2,474
|
260
|
-
|
3,194
|
3,266
|
Proved
undeveloped
|
563
|
1,587
|
41,403
|
43,553
|
5,159
|
63
|
283,680
|
96,002
|
Total
proved
|
5,534
|
14,663
|
85,281
|
105,477
|
12,048
|
18,008
|
743,705
|
244,478
|
Total
probable
|
1,906
|
4,542
|
51,224
|
57,672
|
6,929
|
5,928
|
195,781
|
98,219
|
Proved plus
Probable
|
7,440
|
19,204
|
136,505
|
163,149
|
18,977
|
23,936
|
939,485
|
342,697
|
Reserves Reconciliation
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a gross basis, from
December 31, 2019 to December 31, 2020.
Proved Reserves -
Gross Volumes (Forecast Prices)
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight
Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Proved Reserves
at
Dec. 31, 2019
|
7,770
|
20,121
|
112,812
|
140,703
|
14,327
|
24,242
|
933,737
|
314,693
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
-
|
-
|
12,111
|
12,111
|
1,636
|
-
|
76,643
|
26,521
|
Economic
factors
|
(465)
|
(1,082)
|
(5,668)
|
(7,215)
|
(849)
|
(2,195)
|
(9,970)
|
(10,092)
|
Technical
revisions
|
529
|
(666)
|
890
|
754
|
1,802
|
(824)
|
11,606
|
4,352
|
Production
|
(1,197)
|
(1,428)
|
(13,959)
|
(16,584)
|
(2,016)
|
(3,870)
|
(82,470)
|
(32,990)
|
Proved Reserves
at
Dec. 31, 2020
|
6,637
|
16,946
|
106,186
|
129,769
|
14,900
|
17,353
|
929,546
|
302,485
|
Probable Reserves
- Gross Volumes (Forecast Prices)
|
|
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight
Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Probable Reserves
at
Dec. 31, 2019
|
2,788
|
6,470
|
68,240
|
77,498
|
8,396
|
7,395
|
233,613
|
126,061
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved
|
-
|
-
|
6,454
|
6,454
|
698
|
-
|
38,538
|
13,576
|
recovery
|
Economic
factors
|
11
|
(506)
|
(1,537)
|
(2,032)
|
(209)
|
(588)
|
(975)
|
(2,501)
|
Technical
revisions
|
(416)
|
(655)
|
(9,216)
|
(10,287)
|
(284)
|
(997)
|
(26,788)
|
(15,202)
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Probable Reserves
at
Dec. 31, 2020
|
2,383
|
5,309
|
63,941
|
71,633
|
8,602
|
5,811
|
244,388
|
121,934
|
|
|
|
|
|
|
|
|
|
|
Proved Plus
Probable Reserves - Gross Volumes (Forecast Prices)
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight
Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Proved Plus
Probable
Reserves at Dec. 31, 2019
|
10,558
|
26,591
|
181,052
|
218,201
|
22,723
|
31,637
|
1,167,349
|
440,755
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved
|
-
|
-
|
18,565
|
18,565
|
2,335
|
-
|
115,181
|
40,097
|
recovery
|
Economic
factors
|
(454)
|
(1,589)
|
(7,205)
|
(9,248)
|
(1,058)
|
(2,783)
|
(10,946)
|
(12,593)
|
Technical
revisions
|
113
|
(1,320)
|
(8,326)
|
(9,533)
|
1,518
|
(1,821)
|
(15,181)
|
(10,849)
|
Production
|
(1,197)
|
(1,428)
|
(13,959)
|
(16,584)
|
(2,016)
|
(3,870)
|
(82,470)
|
(32,990)
|
Proved Plus
Probable
Reserves at Dec. 31, 2020
|
9,020
|
22,254
|
170,127
|
201,402
|
23,501
|
23,164
|
1,173,934
|
424,419
|
Future Development Costs
Changes in forecast FDC occur annually as a result of
development activities, acquisition and divestment activities and
capital cost estimates that reflect the evaluators' best estimate
of the capital required to bring the proved and proved plus
probable reserves on production. The aggregate of the exploration
and development costs incurred in the most recent year and the
change during the year in estimated FDC generally reflect the total
finding and development costs related to reserves additions for
that year.
The following is a summary of the estimated FDC required to
bring the total proved and proved plus probable reserves on
production:
Future Development
Costs
|
Proved
Reserves
|
Proved
Plus
Probable
Reserves
|
($
millions)
|
|
2021
|
258
|
260
|
2022
|
314
|
315
|
2023
|
321
|
344
|
2024
|
264
|
378
|
2025
|
34
|
303
|
2026
|
3
|
277
|
Remainder
|
3
|
6
|
Total FDC
Undiscounted
|
1,197
|
1,883
|
Total FDC
Discounted at 10%
|
989
|
1,431
|
F&D and
FD&A Costs – including FDC
|
|
($ millions except
for per BOE amounts)
|
2020
|
2019
|
2018
|
3
Year
|
Proved Plus
Probable Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$291.4
|
$618.9
|
$593.8
|
$1,504.1
|
Net change in Future
Development Costs
|
$(183.2)
|
$47.0
|
$309.1
|
$172.9
|
Gross Reserves
additions (MMBOE)
|
16.7
|
51.0
|
65.7
|
133.4
|
F&D costs
($/BOE)
|
$6.50
|
$13.05
|
$13.74
|
$12.57
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$295.4
|
$633.7
|
$612.7
|
$1,541.8
|
Net change in Future
Development Costs
|
$(183.2)
|
$44.0
|
$308.1
|
$168.8
|
Gross Reserves
additions (MMBOE)
|
16.7
|
49.7
|
64.1
|
130.4
|
FD&A costs
($/BOE)
|
$6.74
|
$13.63
|
$14.37
|
$13.12
|
|
|
|
|
|
Proved
Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$291.4
|
$618.9
|
$593.8
|
$1,504.1
|
Net change in Future
Development Costs
|
$(150.5)
|
$2.4
|
$309.3
|
$161.2
|
Gross Reserves
additions (MMBOE)
|
20.8
|
54.6
|
54.1
|
129.5
|
F&D costs
($/BOE)
|
$6.78
|
$11.37
|
$16.69
|
$12.86
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$295.4
|
$633.7
|
$612.7
|
$1,541.8
|
Net change in Future
Development Costs
|
$(150.5)
|
$(0.5)
|
$308.3
|
$157.3
|
Gross Reserves
additions (MMBOE)
|
20.8
|
53.6
|
52.9
|
127.2
|
FD&A costs
($/BOE)
|
$6.97
|
$11.82
|
$17.42
|
$13.35
|
|
|
|
|
|
Proved Developed
Producing Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$291.4
|
$618.9
|
$593.8
|
$1,504.1
|
Gross Reserves
additions (MMBOE)
|
11.0
|
38.8
|
45.4
|
95.1
|
F&D costs
($/BOE)
|
$26.51
|
$15.97
|
$13.08
|
$15.81
|
|
|
|
|
|
|
Forecast Price Assumptions
The forecast price and cost case assumes no legislative or
regulatory amendments, and includes the effects of inflation. The
estimated future net revenue to be derived from the production of
the reserves is based on the following average of the price
forecasts of McDaniel, GLJ and Sproule as of January 1, 2021 (utilized by McDaniel, NSAI and
by the Company in its internal evaluations for consistency in the
Company's reserves reporting), and the following inflation and
exchange rate assumptions.
|
WTI
Crude Oil(1)
US$/bbl
|
Light
Crude
Oil(2)
Edmonton
CDN$/bbl
|
Alberta
Heavy
Crude Oil(3)
CDN$/bbl
|
U.S. Henry
Hub Gas
Price
US$/MMBtu
|
Exchange
Rate
US$/CDN$
|
Inflation
Rate
%/year
|
|
|
|
|
|
|
|
2021
|
47.17
|
55.76
|
39.87
|
2.83
|
0.768
|
0.0
|
2022
|
50.17
|
59.89
|
43.20
|
2.87
|
0.765
|
1.3
|
2023
|
53.17
|
63.48
|
46.86
|
2.90
|
0.763
|
2.0
|
2024
|
54.97
|
65.76
|
48.67
|
2.96
|
0.763
|
2.0
|
2025
|
56.07
|
67.13
|
49.65
|
3.02
|
0.763
|
2.0
|
2026
|
57.19
|
68.53
|
50.65
|
3.08
|
0.763
|
2.0
|
2027
|
58.34
|
69.95
|
51.67
|
3.14
|
0.763
|
2.0
|
2028
|
59.50
|
71.40
|
52.71
|
3.20
|
0.763
|
2.0
|
2029
|
60.69
|
72.88
|
53.76
|
3.26
|
0.763
|
2.0
|
2030
|
61.91
|
74.34
|
54.84
|
3.33
|
0.763
|
2.0
|
2031
|
63.15
|
75.83
|
55.94
|
3.39
|
0.763
|
2.0
|
2032
|
64.41
|
77.34
|
57.05
|
3.46
|
0.763
|
2.0
|
2033
|
65.70
|
78.89
|
58.20
|
3.53
|
0.763
|
2.0
|
2034
|
67.01
|
80.47
|
59.36
|
3.60
|
0.763
|
2.0
|
2035
|
68.35
|
82.08
|
60.55
|
3.67
|
0.763
|
2.0
|
Thereafter
|
(4)
|
(4)
|
(4)
|
(4)
|
0.763
|
2.0
|
(1)
|
West Texas
Intermediate at Cushing, Oklahoma 40 degree API / 0.5%
Sulphur.
|
(2)
|
Edmonton Light Sweet
40 degree API, 0.3% Sulphur.
|
(3)
|
Heavy Crude Oil 12
degree API at Hardisty, Alberta (after deducting blending costs to
reach
pipeline quality).
|
(4)
|
Escalation is
approximately 2% per year thereafter.
|
Net Present Value of Future Production Revenue
The following table provides an estimate of the net present
value of Enerplus' future production revenue after deduction of
royalties, estimated future capital and operating expenditures,
before income taxes. It should not be assumed that the present
value of estimated future cash flows shown below is representative
of the fair market value of the reserves.
Net Present Value
of Future Production Revenue – Forecast Prices and Costs
(before tax)
|
Reserves at December
31, 2020, ($ Millions, discounted at)
|
0%
|
5%
|
10%
|
15%
|
Proved developed
producing
|
1,855
|
1,597
|
1,353
|
1,169
|
Proved developed
non-producing
|
55
|
47
|
39
|
33
|
Proved
undeveloped
|
1,118
|
700
|
449
|
290
|
Total
Proved
|
3,028
|
2,344
|
1,841
|
1,492
|
Probable
|
1,990
|
1,171
|
755
|
526
|
Total Proved Plus
Probable Reserves (before tax)
|
5,019
|
3,515
|
2,596
|
2,018
|
Contingent Resources
The following table provides a breakdown of the economic,
unrisked best estimate contingent resources associated with a
portion of Enerplus' Fort Berthold and Marcellus assets as at
December 31, 2020. These
contingent resources are economic using the average of the three
independent petroleum consulting firms' price forecasts (McDaniel,
GLJ and Sproule) as of January 1,
2021, use established technologies and are all classified in
the "development pending" maturity sub-class. However, there is
uncertainty that it will be commercially viable to produce any
portion of the resources.
The evaluation of contingent resources associated with Enerplus'
properties and leases at Fort Berthold were conducted by Enerplus
and audited by McDaniel. NSAI evaluated 100% of Enerplus' Marcellus
shale gas assets in the U.S., including the estimate of contingent
resources.
Please see Enerplus' Annual Information Form ("AIF") – Appendix
A for additional disclosures related to Enerplus' contingent
resources as at December 31, 2020.
The AIF is available at www.enerplus.com as well as on the
Company's SEDAR profile at www.sedar.com.
Development
Pending Contingent Resources
|
Unrisked "Best
Estimate"
Contingent Resources
|
Contingent
Resources
Net Drilling
Locations
|
Fort Berthold –
Bakken/Three Forks Tight oil wells
|
72.0
|
MMBOE
|
136.3
|
Marcellus - Shale
gas
|
621.2
|
Bcf
|
32.6
|
Total
|
175.5
|
MMBOE
|
168.9
|
Live Conference Call
Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today,
February 19, 2021 at 9:00 a.m. MT (11:00 a.m.
ET) to discuss these results. Details of the conference call
are as follows:
Date:
|
Friday, February 19,
2021
|
Time:
|
9:00 am MT/11:00 am
ET
|
Dial-In:
|
416-764-8688
|
|
1-888-390-0546 (toll
free)
|
Conference ID:
87527222
|
Audiocast:
https://produceredition.webcasts.com/starthere.jsp?ei=1418451&tp_key=a39387ec4a
|
To ensure timely participation in the conference call, callers
are encouraged to dial in 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
Dial-In:
|
416-764-8677
|
|
1-888-390-0541 (toll
free)
|
Passcode:
|
527222 #
|
Electronic copies of Enerplus' 2020 MD&A and Financial
Statements, along with other public information including investor
presentations, are available on the Company's website at
www.enerplus.com.
Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL
INFORMATION
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 and Reserves Information
All production volumes and revenues presented herein are
reported on a "company interest" basis, before deduction of Crown
and other royalties, plus Enerplus' royalty interest with the
exception of production utilized to calculate reserves replacement
ratios which are on a working interest basis. Unless otherwise
specified, all reserves volumes in this news release (and all
information derived therefrom) are based on "gross reserves" using
forecast prices and costs. "Gross reserves" (as defined in NI
51-101), are Enerplus' working interest before deduction of any
royalties. Enerplus' oil and gas reserves statement for the year
ended December 31, 2020, which will
include complete disclosure of our oil and gas reserves and other
oil and gas information in accordance with NI 51-101, is contained
within our Annual Information Form (AIF) for the year ended
December 31, 2020 which is available
on our website at www.enerplus.com and under our SEDAR profile at
www.sedar.com. Additionally, our AIF forms part of our Form 40-F
that is filed with the U.S. Securities and Exchange Commission and
is available on EDGAR at www.sec.gov. Readers are also urged to
review the Management's Discussion & Analysis and financial
statements filed on SEDAR and as part of our Form 40-F on EDGAR
concurrently with this news release for more complete disclosure on
our operations.
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.
Contingent Resources Estimates
This news release contains estimates of "contingent
resources". "Contingent resources" are not, and should not be
confused with, oil and gas reserves. "Contingent resources" are
defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE
Handbook") as "those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from known accumulations
using established technology or technology under development, but
which are not currently considered to be commercially recoverable
due to one or more contingencies. Contingencies may include factors
such as ultimate recovery rates, legal, environmental, political
and regulatory matters or a lack of markets. It is also appropriate
to classify as "contingent resources" the estimated discovered
recoverable quantities associated with a project in the early
evaluation stage. All of our contingent resources estimates
are economic using established technologies and based on the
average of the price forecasts of McDaniel, GLJ and Sproule as of
January 1, 2021. Enerplus expects to
develop these contingent resources in the coming years however it
is too early in their development for all of these resources to be
classified as reserves at this time. A portion of these contingent
resources are part of continuous development by the Company and are
categorized as contingent resources primarily due to development
timelines that go beyond what is already assigned as undeveloped
reserves. There is uncertainty that Enerplus will produce any
portion of the volumes currently classified as "contingent
resources". "Development pending contingent resources" refer to a
"contingent resources" project maturity sub-class for a particular
project where resolution of the final conditions for development
are being actively pursued (there is a high chance of development)
and the project is expected to be developed in a reasonable
timeframe. The "contingent resources" estimates contained herein
are presented as the "best estimate" of the quantity that will
actually be recovered, effective as of December 31, 2020. A "best estimate" of
contingent resources means that it is equally likely that the
actual remaining quantities recovered will be greater or less than
the best estimate, and if probabilistic methods are used, there
should be at least a 50% probability that the quantities actually
recovered will equal or exceed the best estimate.
For additional information regarding the primary
contingencies which currently prevent the classification of
Enerplus' disclosed "contingent resources" associated with
Enerplus' Marcellus shale gas properties and Fort Berthold
properties as reserves and the positive and negative factors
relevant to the "contingent resources" estimates, see Appendix A to
Enerplus' AIF, a copy of which is available under Enerplus' SEDAR
profile at www.sedar.com, and Enerplus' Form 40-F, a copy of which
is available under Enerplus' EDGAR profile at www.sec.gov.
F&D and FD&A Costs
F&D costs presented in this news release are calculated
(i) in the case of F&D costs for proved developed producing
reserves, by dividing the sum of the exploration and development
costs incurred in the year, by the additions to proved developed
producing reserves in the year, (ii) in the case of F&D costs
for proved reserves, by dividing the sum of exploration and
development costs incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves in the year, and (iii) in the case of F&D costs for
proved plus probable reserves, by dividing the sum of exploration
and development costs incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves in the year. The aggregate of the
exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally reflect total finding and development
costs related to its reserves additions for that year. F&D
costs are presented in Canadian dollars per working interest BOE
unless otherwise specified.
FD&A costs presented in this news release are calculated
(i) in the case of FD&A costs for proved reserves, by dividing
the sum of exploration and development costs and the cost of net
acquisitions incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves including net acquisitions in the year, and (ii) in the
case of FD&A costs for proved plus probable reserves, by
dividing the sum of exploration and development costs and the cost
of net acquisitions incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves including net acquisitions in the
year. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally reflect
total finding, development and acquisition costs related to its
reserves additions for that year. FD&A costs are presented in
Canadian dollars per working interest BOE unless otherwise
specified.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in
this news release has generally been prepared in accordance with
Canadian disclosure standards, which are not comparable in all
respects to United States or other
foreign disclosure standards. Reserves categories such as "proved
reserves" and "probable reserves" may be defined differently under
Canadian requirements than the definitions contained in
the United States Securities and
Exchange Commission (the "SEC") rules. In addition, under Canadian
disclosure requirements and industry practice, reserves and
production are reported using gross (or, as noted above with
respect to production information, "company interest") volumes,
which are volumes prior to deduction of royalty and similar
payments. The practice in the United
States is to report reserves and production using net
volumes, after deduction of applicable royalties and similar
payments. Canadian disclosure requirements require that forecasted
commodity prices be used for reserves evaluations, while the SEC
mandates the use of an average of first day of the month price for
the 12 months prior to the end of the reporting period.
Additionally, the SEC prohibits disclosure of oil and gas resources
in SEC filings, whereas Canadian issuers may disclose oil and gas
resources. Resources are different than, and should not be
construed as reserves. For a description of the definition of, and
the risks and uncertainties surrounding the disclosure of,
contingent resources, see "Contingent Resources Estimates"
above.
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: the
continued uncertainty regarding timing and impact of the COVID-19
pandemic; anticipated completion, including timing, of the Bruin
Acquisition and its expected impacted of on Enerplus' operations
and financial results; expected 2021 production volumes, timing
thereof and the anticipated production mix; the proportion of our
anticipated oil and gas production that is hedged and the
effectiveness of such hedges in protecting our adjusted funds flow;
the results from our drilling program, timing of related
production, and ultimate well recoveries; oil and natural gas
prices and differentials and our commodity risk management programs
in 2021 and in the future; expectations regarding our realized oil
and natural gas prices; future royalty rates on our production and
future production taxes; anticipated cash and non-cash G&A,
share-based compensation and financing expenses; operating and
transportation costs; capital spending levels in 2021, net debt to
adjusted funds-flow ratio, financial capacity and liquidity and
capital resources to fund capital spending and working capital
requirements; and our ESG initiatives, including GHG emissions and
freshwater reduction targets.
The forward-looking information contained in this news
release reflects several material factors, expectations and
assumptions including, without limitation: closing of the Bruin
Acquisition substantially on the terms and timelines previously
announced; that we will conduct our operations and achieve results
of operations as anticipated; that our development plans will
achieve the expected results; that lack of adequate infrastructure
will not result in curtailment of production and/or reduced
realized prices beyond our current expectations; estimated
commodity price, differentials and cost assumptions, including
continued operation of DAPL; 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; the availability of third party services; the
extent of our liabilities; 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, as well as closing of the Bruin Acquisition in early
March 2021: a WTI price
of 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 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
complete the Bruin Acquisition in accordance with its terms or at
all and failure to realize the anticipated benefits of the Bruin
Acquisition; unanticipated operating results, results from our
capital spending activities or production declines; curtailment of
our production due to low realized prices or lack of adequate
infrastructure; changes in tax or environmental laws, royalty rates
or other regulatory matters; 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 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.
SOURCE Enerplus Corporation