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 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, Nov. 4, 2021 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today
announced its third quarter 2021 operating and financial
results, preliminary 2022 capital budget and an increase to its
share repurchase program and dividend. Cash flow from operating
activities for the third quarter was $226.6
million and adjusted funds flow was $255.7 million, compared to $137.0 million and $83.1
million, respectively, in the third 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 third quarter of
2021.
HIGHLIGHTS: THIRD QUARTER AND 2021
- Adjusted funds flow was $255.7
million in the third quarter, which exceeded capital
spending of $80.2 million, generating
free cash flow of $175.5 million
- Achieved record production in the third quarter of 123,454 BOE
per day, 7% higher than the prior quarter and 36% higher than the
prior year period following Enerplus' strategic acquisitions in the
first half of 2021
- Annual 2021 production guidance revised to 113,750 to 114,750
BOE per day due to outperformance, an increase to the guidance
midpoint of 750 BOE per day despite volumes sold in connection with
the Williston Basin
divestment
- Continued volume growth in the fourth quarter with expected
production of 124,500 to 128,500 BOE per day
- 2021 capital spending guidance now $380
million (from $360 to
$400 million)
- Increased estimated 2021 free cash flow to approximately
$540 million based on current forward
strip commodity prices
- Net debt to adjusted funds flow ratio expected to be below 1.0x
by year-end 2021
- Closed the previously announced divestment of non-strategic
interests in the Williston Basin
on November 2, 2021
HIGHLIGHTS: PRELIMINARY 2022 BUDGET AND INCREASED CASH
RETURNS TO SHAREHOLDERS
- Expected 2022 capital spending is approximately $500 million, representing a reinvestment rate of
44% based on current forward strip commodity prices
- Expected annual 2022 production is 122,000 BOE per day,
including 75,000 barrels per day of liquids
- Estimated 2022 free cash flow is $640
million based on current forward strip commodity prices
- Increased share repurchase program to $200 million, representing 7% of Enerplus' market
capitalization, commencing in the fourth quarter of 2021
- Increased quarterly dividend by 8% effective with the
December 15, 2021 payment
"We continue to deliver strong performance in 2021," said
Ian C. Dundas, President and CEO.
"We extended our core Bakken inventory through accretive
acquisitions, generated over $290
million in free cash flow through the first nine months of
the year and we anticipate another $250
million in free cash flow in the fourth quarter. We also
expect to end the year with a net debt to adjusted funds flow ratio
below one times. Looking ahead into 2022, we have a sustainable
plan expected to generate meaningful free cash flow underpinned by
compelling development economics. We remain committed to returning
capital to shareholders which we have continued to demonstrate with
today's announcement of our accelerated share repurchase program
and third dividend increase in 2021."
THIRD QUARTER SUMMARY
Production in the third quarter of 2021 was 123,454 BOE per day,
an increase of 36% compared to the same period a year ago, and 7%
higher than the prior quarter. Crude oil and natural gas liquids
production in the third quarter of 2021 was 78,512 barrels per day,
an increase of 49% compared to the same period a year ago, and 10%
higher than the prior quarter. The increased production compared to
the same period in 2020 was primarily due to the Company's
development activity in the Williston Basin and contribution from its
acquisitions in 2021.
Enerplus reported third quarter 2021 net income of $112.0 million, or $0.44 per basic share, compared to a net loss of
$112.8 million, or $0.51 per basic share, in the same period of the
prior year due to increased production and higher commodity prices
during the current period and non-cash impairments recorded in same
period in 2020. Adjusted net income for the third quarter of 2021
was $107.4 million, or $0.42 per basic share, compared to $17.7 million, or $0.08 per basic 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' third quarter 2021 realized Bakken oil price
differential was US$2.09 per barrel
below WTI, compared to US$5.37 per
barrel below WTI in the third quarter of 2020. Bakken differentials
improved relative to the prior year period due to increased
refinery demand and significant excess pipeline capacity in the
region.
The Company's realized Marcellus natural gas price differential
was US$0.45 per Mcf below NYMEX
during the third quarter of 2021 compared to US$0.72 per Mcf below NYMEX in the third quarter
of 2020. The improvement was due to increased natural gas demand
and lower storage levels in 2021.
Third quarter operating expenses were $9.89 per BOE, compared to $7.78 per BOE during the same period in 2020.
Operating expenses in the third quarter of 2021 increased from the
prior year period due to a temporary increase in well service
activity and higher water handling charges as a result of contracts
with price escalators linked to WTI, as well as the increased
liquids weighting in the Company's production mix.
Third quarter transportation costs were $3.61 per BOE and cash general and administrative
("G&A") expenses were $0.95 per
BOE.
Enerplus recorded a current tax recovery of $1.2 million in the third quarter of 2021 related
to the reduction of estimated U.S. taxes in 2021.
Exploration and development capital spending was $80.2 million in the third quarter of 2021. The
Company declared $9.8 million in
dividends in the quarter and repurchased 1,657,650 common shares
under its normal course issuer bid ("NCIB") at an average price of
$7.75 per share for total
consideration of $12.9 million.
Enerplus received a $5.7 million
distribution associated with a privately held investment in the
third quarter which was reflected as an investing activity in the
Condensed Consolidated Statements of Cash Flows.
In the third quarter Enerplus announced the divestment of its
interests in the Sleeping Giant field (Montana) and the Russian Creek area
(North Dakota) which closed on
November 2, 2021. The total cash
consideration was US$115 million,
subject to customary purchase price adjustments. In addition,
Enerplus will receive up to US$5
million in contingent consideration if WTI averages over
US$65 per barrel in 2022 and
US$60 per barrel in 2023. The
production associated with Enerplus' working interest in these
properties was approximately 3,000 BOE per day (76% tight oil, 1%
natural gas liquids, and 23% natural gas).
At the end of the third quarter of 2021, the Company had total
debt of $1,101.8 million and cash on
hand of $54.1 million.
Asset Activity
Williston Basin production
averaged 80,561 BOE per day (74% crude oil) during the third
quarter of 2021, an increase of 65% compared to the same period a
year ago, and 11% higher than the prior quarter. During the third
quarter, the Company drilled eight gross operated wells (100%
working interest) and brought 16 gross operated wells on production
(63% average working interest).
Marcellus production averaged 192 MMcf per day during the third
quarter of 2021, an increase of 4% compared to the same period in
2020, and flat with the prior quarter.
Canadian waterflood production averaged 7,562 BOE per day (94%
crude oil) during the third quarter of 2021, a decrease of 2%
compared to the same period in 2020, and 4% higher than the prior
quarter.
2021 GUIDANCE UPDATE
Capital spending guidance was updated to $380 million, the midpoint of the previous range
of $360 to $400 million.
Enerplus revised its annual 2021 production guidance to reflect
outperformance in North Dakota and
the Marcellus which is expected to more than offset the impact to
2021 production from its Williston
Basin divestment during the fourth quarter. Total production is
expected to average 113,750 to 114,750 BOE per day, including
liquids production of 69,750 to 70,750 barrels per day.
Fourth quarter production is expected to average 124,500 to
128,500 BOE per day, including liquids production of 80,000 to
83,000 barrels per day.
Given improved pricing year to date and ongoing commodity market
strength, 2021 Bakken and Marcellus differential guidance was
narrowed to US$2.00 per barrel below
WTI and US$0.55 per Mcf below NYMEX,
respectively.
As a result of higher third quarter operating expenses, full
year 2021 operating expenses are expected to average $8.80 per BOE. Operating expenses in the fourth
quarter are also expected to average $8.80 per BOE as workover activity is expected to
return to normalized levels.
Cash G&A expense guidance was reduced to $1.15 per BOE.
Current income tax expense guidance was reduced to US$3 million in 2021.
A summary of the Company's 2021 and fourth quarter guidance is
provided below.
2021 Guidance
Capital
spending
|
$380 million (from
$360 to $400 million)
|
Average annual
production
|
113,750 – 114,750
BOE/day (from 112,000 – 115,000 BOE/day)
|
Average annual crude
oil and natural gas liquids production
|
69,750 – 70,750
bbls/day (from 69,500 – 71,500 bbls/day)
|
Average royalty and
production tax rate
|
26%
|
Operating
expense
|
$8.80/BOE (from
$8.25/BOE)
|
Transportation
expense
|
$3.85/BOE
|
Cash G&A
expense
|
$1.15/BOE (from
$1.25/BOE)
|
Current Income Tax
expense
|
US$3 million (from
US$5 – $7 million)
|
Q4 2021 Guidance
Q4 average
production
|
124,500 – 128,500
BOE/day
|
Q4 average crude oil
and natural gas liquids production
|
80,000 – 83,000
bbls/day
|
Q4 operating
expense
|
$8.80/BOE
|
2021 Full-Year Differential/Basis Outlook
(1)
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(2.00)/bbl (from
US$(2.35)/bbl)
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.55)/Mcf (from
US$(0.65)/Mcf)
|
(1) Excluding
transportation costs.
|
PRELIMINARY 2022 BUDGET
Enerplus' preliminary 2022 capital budget is approximately
$500 million, expected to result in
average production of approximately 122,000 BOE per day, including
75,000 barrels per day of liquids.
Over 80% of the capital budget is expected to be allocated to
North Dakota with drilling and
completions activity focused on the Fort Berthold Indian
Reservation, Little Knife and Murphy Creek areas.
Enerplus has secured approximately 75% of its total well cost
structure in 2022 for its North
Dakota program, helping to protect against inflationary
pressures. Through solid execution, Enerplus expects its total
wells costs in 2021 to average US$5.7
million, 10% lower than 2020 despite recent inflationary
pressures. In 2022, based on the Company's current inflation
expectations, Enerplus expects its total well costs in North Dakota to increase by 5% to 7%
year-over-year.
The Company plans to announce its comprehensive 2022 budget in
January 2022.
INCREASING CASH RETURNS TO SHAREHOLDERS
With visibility to achieving its net debt reduction target in
the fourth quarter of 2021 and a strong free cash flow outlook in
2022, Enerplus' Board of Directors has approved an acceleration of
the Company's return of capital plans through an expanded share
repurchase program and an 8% dividend increase.
Enerplus expects to commence the execution of a $200 million share repurchase program in the
fourth quarter of 2021 under its existing normal course issuer bid.
Repurchases are expected to be funded out of fourth quarter 2021
and first quarter 2022 free cash flow, representing approximately
50% of forecasted free cash flow over this period based on current
forward strip commodity prices. Enerplus believes the market price
of its common shares are trading in a range that does not
adequately reflect their underlying value based on mid-cycle
commodity prices and, as a result, considers share repurchases to
be a compelling investment opportunity.
Enerplus is increasing its quarterly dividend to $0.041 per share payable on December 15, 2021 to shareholders of record on
November 30, 2021. This is Enerplus'
third dividend increase year to date following its strategic
acquisitions in North Dakota and
represents a 37% increase, on an annualized basis, from the
Company's dividend level at the start of the year. This dividend
per share increase is expected to maintain the Company's current
annual dividend expenditure at approximately $39 million following the execution of its share
repurchase program. Enerplus estimates its dividend is fully funded
from free cash flow down to approximately US$40 WTI.
Enerplus remains committed to returning a significant portion of
free cash flow to shareholders and will continue to evaluate
further cash returns in 2022. Excess free cash flow which is not
returned to shareholders will be allocated to reinforcing the
balance sheet.
DIRECTOR RETIREMENT
Enerplus today announced the planned retirement of Elliott Pew from its board of directors prior to
year-end 2021. Mr. Pew has been a valued member of the board
of directors since his appointment in 2010, including serving as
Board Chair between May 2014 and
May 2020.
"On behalf of the board, I would like to thank Elliott for his
dedication and leadership," said Mr. Dundas. "Elliott has been a
highly-engaged director throughout his tenure and the board and
company have greatly benefitted from his guidance."
Q3 2021 CONFERENCE CALL DETAILS
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM
ET) on Friday, November 5,
2021 to discuss these results. Details of the conference
call are as follows:
|
|
Date:
|
Friday, November 5,
2021
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
Conference
ID:
|
22989526
|
Audiocast:
|
https://produceredition.webcasts.com/starthere.jsp?ei=1501958&tp_key=661d09508f
|
To ensure timely participation in the conference call, callers
are encouraged to dial in 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
Replay
Dial-In:
|
1-888-390-0541 (Toll
Free)
|
Replay
Passcode:
|
989526 #
|
RISK MANAGEMENT
Enerplus' commodity hedging positions
are provided in the table below.
Enerplus' Financial Commodity Hedging Contracts (at
November 3, 2021)
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil (1)(2)
(US$/bbl)
|
|
|
|
|
Oct 1,
2021 –
|
|
Jan 1,
2022 –
|
|
Jan 1,
2022 –
|
|
|
|
|
Dec
31, 2021
|
|
Jun 30,
2022
|
|
Dec 31,
2022
|
3-way
Collars
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
|
|
23,000
|
|
12,500
|
|
17,000
|
Sold Puts
|
|
|
|
$ 36.39
|
|
$ 58.00
|
|
$ 40.00
|
Purchased
Puts
|
|
|
|
$ 46.39
|
|
$ 75.00
|
|
$ 50.00
|
Sold Calls
|
|
|
|
$ 56.70
|
|
$ 87.63
|
|
$ 57.91
|
|
|
|
|
|
|
|
|
|
|
|
Oct 1,
2021 –
|
|
Jan 1,
2022 –
|
|
Oct 1,
2022 –
|
|
Jan 1,
2023 –
|
Contracts acquired
from Bruin(3)
|
|
Dec 31,
2021
|
|
Sep 30,
2022
|
|
Dec 31,
2022
|
|
Dec 31,
2023
|
Swaps
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
7,179
|
|
4,500
|
|
1,834
|
|
208
|
Sold Swaps
|
|
$ 43.01
|
|
$ 42.31
|
|
$ 42.65
|
|
$ 42.10
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
Volume
(bbls/day)
|
|
–
|
|
–
|
|
–
|
|
2,000
|
Purchased
Puts
|
|
–
|
|
–
|
|
–
|
|
$ 5.00
|
Sold Calls
|
|
–
|
|
–
|
|
–
|
|
$ 75.00
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Natural Gas
(US$/Mcf)
|
|
|
|
|
Oct 1, 2021 –
|
|
Nov 1, 2021 –
|
|
Apr 1, 2022 –
|
|
|
|
|
Oct
31, 2021
|
|
Mar
31, 2022
|
|
Oct
31, 2022
|
Swaps
|
|
|
|
|
|
|
|
|
Volume
(mcf/day)
|
|
|
|
60,000
|
|
–
|
|
40,000
|
Sold Swaps
|
|
|
|
$ 2.90
|
|
–
|
|
$ 3.40
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
|
Volume
(mcf/day)
|
|
|
|
40,000
|
|
40,000
|
|
–
|
Sold Puts
|
|
|
|
$ 2.15
|
|
–
|
|
–
|
Purchased
Puts
|
|
|
|
$ 2.75
|
|
$ 3.43
|
|
–
|
Sold Calls
|
|
|
|
$ 3.25
|
|
$ 6.00
|
|
–
|
(1)
|
The total average
deferred premium spent on outstanding contracts is US$0.87/bbl from
October 1, 2021 - December 31, 2021 and US$1.29/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 contracts were recorded at a
fair value liability of $96.5 million. At September 30, 2021, the
fair value of the Bruin contracts was a liability of $82.6 million,
including $42.6 million of the original $96.5 million liability
acquired. For the three and nine months ended September 30, 2021 we
recorded a realized loss of $10.3 million and $11.9 million,
respectively, on the settlement of the Bruin contracts. In
addition, we recognized an unrealized loss of $4.6 million and
$40.0 million, respectively, for the change in the fair value of
the Bruin contracts over the same periods. See Note 17 to the Q3
2021 Financial Statements for further detail.
|
THIRD QUARTER PRODUCTION AND OPERATIONAL SUMMARY
TABLES
Average Daily Production(1)
|
Three months ended
September 30, 2021
|
|
Nine months ended
September 30, 2021
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-
floods
|
Other(2)
|
Total
|
|
Williston
Basin
|
Marcellus
|
Canadian
Water-
floods
|
Other(2)
|
Total
|
Tight oil
(bbl/d)
|
59,338
|
-
|
-
|
1,375
|
60,712
|
|
48,999
|
-
|
-
|
1,356
|
50,355
|
Light & medium
oil (bbl/d)
|
-
|
-
|
3,012
|
35
|
3,048
|
|
-
|
-
|
2,984
|
55
|
3,039
|
Heavy oil
(bbl/d)
|
-
|
-
|
4,118
|
31
|
4,150
|
|
-
|
-
|
4,070
|
22
|
4,092
|
Total crude oil
(bbl/d)
|
59,338
|
-
|
7,131
|
1,441
|
67,910
|
|
48,999
|
-
|
7,054
|
1,433
|
57,486
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
liquids (bbl/d)
|
9,991
|
-
|
107
|
504
|
10,602
|
|
8,429
|
-
|
86
|
524
|
9,039
|
|
|
|
|
|
|
|
|
|
|
|
|
Shale gas
(Mcf/d)
|
67,394
|
192,427
|
-
|
1,371
|
261,192
|
|
56,723
|
195,963
|
-
|
1,348
|
254,034
|
Conventional natural
gas (Mcf/d)
|
-
|
-
|
1,945
|
6,514
|
8,460
|
|
-
|
-
|
1,476
|
6,989
|
8,465
|
Total natural gas
(Mcf/d)
|
67,394
|
192,427
|
1,945
|
7,886
|
269,652
|
|
56,723
|
195,963
|
1,476
|
8,337
|
262,499
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production
(BOE/d)
|
80,561
|
32,071
|
7,562
|
3,260
|
123,454
|
|
66,881
|
32,660
|
7,386
|
3,347
|
110,275
|
(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, 2021
|
|
Nine months
ended September 30, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
8
|
8.0
|
|
14
|
0.3
|
|
12
|
12.0
|
|
14
|
0.3
|
Marcellus
|
-
|
-
|
|
21
|
1.1
|
|
-
|
-
|
|
49
|
1.8
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
2
|
0.3
|
Total
|
8
|
8.0
|
|
35
|
1.4
|
|
12
|
12.0
|
|
65
|
2.5
|
(1) Table
may not add due to rounding.
|
(2) Comprises DJ Basin and non-core
properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended September 30, 2021
|
|
Nine months
ended
September 30, 2021
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
16
|
10.1
|
|
-
|
-
|
|
42
|
32.1
|
|
1
|
0.4
|
Marcellus
|
-
|
-
|
|
18
|
0.3
|
|
-
|
-
|
|
54
|
2.1
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
3
|
2.6
|
|
2
|
0.3
|
Total
|
16
|
10.1
|
|
18
|
0.3
|
|
45
|
34.7
|
|
57
|
2.8
|
(1) Table may not add due to
rounding.
|
(2) Comprises DJ Basin and non-core
properties in Canada.
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED FINANCIAL
RESULTS
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
2021
|
2020
|
|
2021
|
2020
|
Financial (CDN$,
thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
112,009
|
$
|
(112,753)
|
|
$
|
67,042
|
$
|
(719,200)
|
Adjusted Net
Income/(Loss)(1)
|
|
107,358
|
|
17,705
|
|
|
231,541
|
|
(2,391)
|
Cash Flow from
Operating Activities
|
|
226,642
|
|
136,987
|
|
|
400,783
|
|
350,286
|
Adjusted Funds
Flow(1)
|
|
255,748
|
|
83,065
|
|
|
568,183
|
|
266,289
|
Dividends to
Shareholders - Declared
|
|
9,757
|
|
6,676
|
|
|
28,162
|
|
20,021
|
Total Debt Net of
Cash(1)
|
|
1,047,727
|
|
428,768
|
|
|
1,047,727
|
|
428,768
|
Capital
Spending
|
|
80,241
|
|
35,345
|
|
|
275,675
|
|
239,054
|
Property and Land
Acquisitions
|
|
3,848
|
|
2,388
|
|
|
1,041,180
|
|
8,060
|
Property
Divestments
|
|
(271)
|
|
583
|
|
|
4,707
|
|
6,098
|
Net Debt to Adjusted
Funds Flow Ratio(1)(2)
|
|
1.6x
|
|
1.0x
|
|
|
1.6x
|
|
1.0x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net Income /(Loss) -
Basic
|
$
|
0.44
|
$
|
(0.51)
|
|
$
|
0.27
|
$
|
(3.23)
|
Net Income/(Loss) -
Diluted
|
|
0.43
|
|
(0.51)
|
|
|
0.26
|
|
(3.23)
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
256,345
|
|
222,548
|
|
|
252,432
|
|
222,487
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
260,831
|
|
222,548
|
|
|
256,900
|
|
222,487
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(3)(4)
|
|
|
|
|
|
|
|
|
|
Crude Oil &
Natural Gas Sales(5)
|
$
|
58.47
|
$
|
28.65
|
|
$
|
50.94
|
$
|
26.95
|
Royalties and
Production Taxes
|
|
(15.07)
|
|
(7.36)
|
|
|
(12.99)
|
|
(6.94)
|
Commodity Derivative
Instruments
|
|
(5.50)
|
|
2.36
|
|
|
(3.95)
|
|
4.21
|
Operating
Expenses
|
|
(9.89)
|
|
(7.78)
|
|
|
(8.81)
|
|
(7.86)
|
Transportation
Costs
|
|
(3.61)
|
|
(3.85)
|
|
|
(3.66)
|
|
(4.02)
|
Cash General and
Administrative Expenses
|
|
(0.95)
|
|
(1.40)
|
|
|
(1.15)
|
|
(1.33)
|
Cash Share-Based
Compensation
|
|
(0.09)
|
|
0.09
|
|
|
(0.20)
|
|
0.09
|
Interest, Foreign
Exchange and Other Expenses
|
|
(0.94)
|
|
(0.82)
|
|
|
(1.21)
|
|
(1.14)
|
Current Income Tax
Recovery/(Expense)
|
|
0.10
|
|
0.02
|
|
|
(0.10)
|
|
0.57
|
Adjusted Funds
Flow(1)
|
$
|
22.52
|
$
|
9.91
|
|
$
|
18.87
|
$
|
10.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED OPERATING
RESULTS
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
2021
|
2020
|
|
2021
|
2020
|
Average Daily
Production(4)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
67,910
|
|
46,082
|
|
|
57,486
|
|
46,098
|
Natural Gas Liquids
(bbls/day)
|
|
10,602
|
|
6,457
|
|
|
9,039
|
|
5,581
|
Natural Gas
(Mcf/day)
|
|
269,652
|
|
230,895
|
|
|
262,499
|
|
243,083
|
Total
(BOE/day)
|
|
123,454
|
|
91,022
|
|
|
110,275
|
|
92,193
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
64%
|
|
58%
|
|
|
60%
|
|
56%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (4)(5)
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
$
|
84.92
|
$
|
46.43
|
|
$
|
77.68
|
$
|
43.21
|
Natural Gas Liquids
(per bbl)
|
|
38.86
|
|
10.60
|
|
|
32.33
|
|
7.88
|
Natural Gas (per
Mcf)
|
|
3.84
|
|
1.72
|
|
|
3.26
|
|
1.82
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
9
|
|
3
|
|
|
14
|
|
40
|
(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 Brun and Dunn County
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 the effects of commodity derivative
instruments.
|
Condensed Consolidated Balance Sheets
|
|
|
|
|
|
(CDN$ thousands) unaudited
|
September
30, 2021
|
|
December 31, 2020
|
Assets
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
54,114
|
|
$
|
114,455
|
Accounts
receivable
|
|
298,619
|
|
|
106,376
|
Derivative financial
assets
|
|
8,966
|
|
|
3,550
|
Other current
assets
|
|
—
|
|
|
7,137
|
|
|
361,699
|
|
|
231,518
|
Property, plant and
equipment:
|
|
|
|
|
|
Crude oil and natural
gas properties (full cost method)
|
|
1,702,251
|
|
|
575,559
|
Other capital assets,
net
|
|
24,944
|
|
|
19,524
|
Property, plant and
equipment
|
|
1,727,195
|
|
|
595,083
|
Right-of-use
assets
|
|
35,094
|
|
|
32,853
|
Deferred income tax
asset
|
|
567,622
|
|
|
607,001
|
Total
Assets
|
$
|
2,691,610
|
|
$
|
1,466,455
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
Accounts
payable
|
$
|
415,970
|
|
$
|
251,822
|
Dividends
payable
|
|
—
|
|
|
2,225
|
Current portion of
long-term debt
|
|
127,561
|
|
|
103,836
|
Derivative financial
liabilities
|
|
241,658
|
|
|
19,261
|
Current portion of
lease liabilities
|
|
13,489
|
|
|
13,391
|
|
|
798,678
|
|
|
390,535
|
|
|
|
|
|
|
Long-term
debt
|
|
974,280
|
|
|
386,586
|
Asset retirement
obligation
|
|
162,099
|
|
|
130,208
|
Derivative financial
liabilities
|
|
42,813
|
|
|
—
|
Lease
liabilities
|
|
25,228
|
|
|
23,446
|
|
|
1,204,420
|
|
|
540,240
|
Total
Liabilities
|
|
2,003,098
|
|
|
930,775
|
|
|
|
|
|
|
Shareholders'
Equity
|
|
|
|
|
|
Share capital –
authorized unlimited common shares, no par value
Issued and
outstanding: September 30, 2021 – 255 million shares
December
31, 2020 – 223 million shares
|
|
3,215,224
|
|
|
3,096,969
|
Paid-in
capital
|
|
40,513
|
|
|
50,604
|
Accumulated
deficit
|
|
(2,885,099)
|
|
|
(2,932,017)
|
Accumulated other
comprehensive income/(loss)
|
|
317,874
|
|
|
320,124
|
|
|
688,512
|
|
|
535,680
|
Total Liabilities
& Shareholders' Equity
|
$
|
2,691,610
|
|
$
|
1,466,455
|
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Nine months
ended
|
|
September 30,
|
|
September 30,
|
(CDN$ thousands,
except per share amounts) unaudited
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural
gas sales, net of royalties
|
$
|
531,220
|
|
$
|
191,944
|
|
$
|
1,228,643
|
|
$
|
542,140
|
Commodity derivative
instruments gain/(loss)
|
|
(78,947)
|
|
|
894
|
|
|
(346,757)
|
|
|
121,340
|
|
|
452,273
|
|
|
192,838
|
|
|
881,886
|
|
|
663,480
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
112,309
|
|
|
65,129
|
|
|
265,290
|
|
|
198,502
|
Transportation
|
|
41,008
|
|
|
32,209
|
|
|
110,019
|
|
|
101,544
|
Production
taxes
|
|
38,293
|
|
|
13,610
|
|
|
86,247
|
|
|
36,741
|
General and
administrative
|
|
15,635
|
|
|
8,392
|
|
|
44,381
|
|
|
41,071
|
Depletion,
depreciation and accretion
|
|
102,380
|
|
|
62,147
|
|
|
242,748
|
|
|
237,224
|
Asset
impairment
|
|
—
|
|
|
256,809
|
|
|
4,300
|
|
|
683,619
|
Goodwill
impairment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
202,767
|
Interest
|
|
10,451
|
|
|
6,339
|
|
|
26,801
|
|
|
22,301
|
Foreign exchange
(gain)/loss
|
|
(12,297)
|
|
|
946
|
|
|
(5,311)
|
|
|
(3,198)
|
Transaction costs and
other expense/(income)
|
|
(5,898)
|
|
|
123
|
|
|
(2,092)
|
|
|
6,195
|
|
|
301,881
|
|
|
445,704
|
|
|
772,383
|
|
|
1,526,766
|
Income/(Loss)
before taxes
|
|
150,392
|
|
|
(252,866)
|
|
|
109,503
|
|
|
(863,286)
|
Current income tax
expense/(recovery)
|
|
(1,172)
|
|
|
(130)
|
|
|
3,003
|
|
|
(14,525)
|
Deferred income tax
expense/(recovery)
|
|
39,555
|
|
|
(139,983)
|
|
|
39,458
|
|
|
(129,561)
|
Net
Income/(Loss)
|
$
|
112,009
|
|
$
|
(112,753)
|
|
$
|
67,042
|
|
$
|
(719,200)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain/(loss) on foreign currency translation
|
|
21,585
|
|
|
(21,559)
|
|
|
(5,627)
|
|
|
52,931
|
Foreign exchange
gain/(loss) on net investment hedge with U.S. denominated debt, net
of tax
|
|
(19,847)
|
|
|
9,905
|
|
|
3,377
|
|
|
(20,691)
|
Total
Comprehensive Income/(Loss)
|
$
|
113,747
|
|
$
|
(124,407)
|
|
$
|
64,792
|
|
$
|
(686,960)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(Loss)
per share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.44
|
|
$
|
(0.51)
|
|
$
|
0.27
|
|
$
|
(3.23)
|
Diluted
|
$
|
0.43
|
|
$
|
(0.51)
|
|
$
|
0.26
|
|
$
|
(3.23)
|
Condensed Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
|
|
Nine months
ended
|
|
September 30,
|
|
September 30,
|
(CDN$ thousands) unaudited
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Operating
Activities
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss)
|
$
|
112,009
|
|
$
|
(112,753)
|
|
$
|
67,042
|
|
$
|
(719,200)
|
Non-cash items
add/(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and accretion
|
|
102,380
|
|
|
62,147
|
|
|
242,748
|
|
|
237,224
|
Asset
impairment
|
|
—
|
|
|
256,809
|
|
|
4,300
|
|
|
683,619
|
Goodwill
impairment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
202,767
|
Changes in fair value
of derivative instruments
|
|
16,174
|
|
|
19,214
|
|
|
226,146
|
|
|
(13,285)
|
Deferred income tax
expense/(recovery)
|
|
39,555
|
|
|
(139,983)
|
|
|
39,458
|
|
|
(129,561)
|
Foreign exchange
(gain)/loss on debt and working capital
|
|
(12,680)
|
|
|
487
|
|
|
(6,822)
|
|
|
(890)
|
Share-based
compensation and general and administrative
|
|
4,128
|
|
|
(2,898)
|
|
|
5,118
|
|
|
8,285
|
Other
expense/(income)
|
|
(264)
|
|
|
—
|
|
|
(2,617)
|
|
|
—
|
Amortization of debt
issuance costs
|
|
534
|
|
|
—
|
|
|
919
|
|
|
—
|
Translation of U.S.
dollar cash held in Canada
|
|
(368)
|
|
|
42
|
|
|
(2,389)
|
|
|
(2,670)
|
Other income
reclassified to Investing Activities
|
|
(5,720)
|
|
|
—
|
|
|
(5,720)
|
|
|
—
|
Asset retirement
obligation settlements
|
|
(2,142)
|
|
|
(1,905)
|
|
|
(10,581)
|
|
|
(13,032)
|
Changes in non-cash
operating working capital
|
|
(26,964)
|
|
|
55,827
|
|
|
(156,819)
|
|
|
97,029
|
Cash flow from/(used
in) operating activities
|
|
226,642
|
|
|
136,987
|
|
|
400,783
|
|
|
350,286
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
|
|
|
|
|
|
|
|
|
Bank term
loan
|
|
—
|
|
|
—
|
|
|
501,286
|
|
|
—
|
Bank credit
facility
|
|
(131,706)
|
|
|
(1,364)
|
|
|
201,910
|
|
|
—
|
Repayment of senior
notes
|
|
—
|
|
|
—
|
|
|
(99,348)
|
|
|
(114,010)
|
Proceeds from the
issuance of shares
|
|
—
|
|
|
—
|
|
|
125,746
|
|
|
—
|
Purchase of common
shares under Normal Course Issuer Bid
|
|
(12,855)
|
|
|
—
|
|
|
(12,855)
|
|
|
(2,536)
|
Share-based
compensation – cash settled (tax withholding)
|
|
—
|
|
|
—
|
|
|
(4,491)
|
|
|
(7,232)
|
Dividends
|
|
(9,757)
|
|
|
(6,676)
|
|
|
(30,384)
|
|
|
(20,013)
|
Cash flow from/(used
in) financing activities
|
|
(154,318)
|
|
|
(8,040)
|
|
|
681,864
|
|
|
(143,791)
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities
|
|
|
|
|
|
|
|
|
|
|
|
Capital and office
expenditures
|
|
(96,073)
|
|
|
(47,228)
|
|
|
(240,257)
|
|
|
(280,681)
|
Bruin
acquisition
|
|
—
|
|
|
—
|
|
|
(531,134)
|
|
|
—
|
Dunn County
acquisition
|
|
—
|
|
|
—
|
|
|
(374,613)
|
|
|
—
|
Property and land
acquisitions
|
|
(5,787)
|
|
|
(2,388)
|
|
|
(10,813)
|
|
|
(8,060)
|
Property
divestments
|
|
(271)
|
|
|
583
|
|
|
4,707
|
|
|
6,098
|
Other
expense/(income)
|
|
5,720
|
|
|
—
|
|
|
5,720
|
|
|
—
|
Cash flow from/(used
in) investing activities
|
|
(96,411)
|
|
|
(49,033)
|
|
|
(1,146,390)
|
|
|
(282,643)
|
Effect of exchange
rate changes on cash & cash equivalents
|
|
2,923
|
|
|
(1,544)
|
|
|
3,402
|
|
|
9,046
|
Change in cash and
cash equivalents
|
|
(21,164)
|
|
|
78,370
|
|
|
(60,341)
|
|
|
(67,102)
|
Cash and cash
equivalents, beginning of period
|
|
75,278
|
|
|
6,177
|
|
|
114,455
|
|
|
151,649
|
Cash and cash
equivalents, end of period
|
$
|
54,114
|
|
$
|
84,547
|
|
$
|
54,114
|
|
$
|
84,547
|
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 statements ("forward-looking information") within
the meaning of applicable securities laws. The use of any of the
words "expect", "anticipate", "continue", "estimate", "guidance",
"believes", "plans", "ongoing", "may", "will", "project", "budget",
"strategy", and similar expressions are intended to identify
forward-looking information. In particular, but without limiting
the foregoing, this news release contains forward-looking
information pertaining to the following: expected impact of the
Dunn County acquisition, the
Bruin acquisition and the Montana
and Russian Creek divestments on Enerplus' operations and financial
results, including expected free cash flow in 2021, 2022 and
beyond; updated 2021 and future capital spending guidance, and
expected capital spending levels in 2022 and the future, and the
impact thereof on our production levels and land holdings; expected
capital spending for 2022 and allocation amongst drilling
completions activity; expected production volumes in fourth quarter
and in 2022, and updated 2021 and future production guidance; the
intention to commence a share repurchase program, including the
timing and terms thereof and quantity of purchases of common shares
thereunder; expectations of funding the increase in dividends and
share repurchase program from free cash flow; expected operating
strategy in 2021; anticipated total well costs in 2021 and the
future and the expected impact of its anticipated 2022 well cost
structure; expectations regarding generation of free cash flow;
2021 average production volumes, timing thereof and the anticipated
production mix; the results from our drilling program and the
timing of related production and ultimate well recoveries; oil and
natural gas prices and differentials and expectations regarding the
market environment, commodity risk management program in 2021 and
expected hedging gains; updated 2021 Marcellus and Bakken
differential guidance; expectations regarding realized oil and
natural gas prices; expected operating, transportation, cash
G&A costs and share-based compensation and financing expenses;
updated 2021 operating expense, cash G&A cost and current tax
expense guidance; future royalty and production and U.S. cash
taxes; deferred income taxes, tax pools and the time at which
Canadian cash taxes may be paid; future debt and working capital
levels and net debt to adjusted funds-flow ratio, financial
capacity, liquidity and capital resources to fund capital spending,
and working capital requirements and deficits; expectations
regarding our ability to comply with or renegotiate debt covenants
under the Bank Credit Facility, term loan and outstanding senior
notes; Enerplus' costs reduction initiatives; expectations
regarding payment of increased dividends and maintenance of current
annual dividend expenditures; and the amount of future cash
dividends that may be paid to shareholders.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: the benefits
of the Dunn County acquisition,
the Bruin acquisition and the Montana and Russian Creek divestments; that
Enerplus will realize the expected impact of the Dunn County acquisition, the Bruin acquisition
and the Montana and Russian Creek
divestments on Enerplus' operations and financial results and that
Enerplus' future costs and expenses will be as expected and as
discussed in this news release; that we will conduct our operations
and achieve results of operations as anticipated; the continued
operation of the Dakota Access Pipeline; that 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 and anticipated commodity
prices, differentials and cost assumptions; the general continuance
of current or, where applicable, assumed industry conditions, the
impact of inflation, weather conditions, storage fundamentals and
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 ability to fund increased dividend payments
and the share repurchase program from free cash flow as expected
and discussed in this news release; the continued availability and
sufficiency of our adjusted funds flow and availability under
Enerplus' Bank Credit Facility to fund working capital
deficiency; Enerplus' ability to comply with its debt covenants;
the availability of third party services; expected transportation
expenses; the extent of liabilities; the rates used to calculate
the amount of our future abandonment and reclamation costs and
asset retirement obligations; factors used to assess the
realizability of our deferred income tax assets; and the
availability of technology and process to achieve environmental
targets. In addition, Enerplus' 2021 outlook contained in this news
release is based on the following prices: a US$68.76/bbl WTI, US$3.87/Mcf NYMEX, and a USD/CDN exchange rate of
1.25. Furthermore, in addition, Enerplus' preliminary 2022
outlook contained in this news release is based on the following: a
WTI price of US$72.88/bbl, a NYMEX
price of US$4.44/Mcf and a USD/CDN
exchange rate of 1.24. 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: failure
by Enerplus to realize anticipated benefits of the Dunn County acquisition, the Bruin acquisition
or the Montana and Russian Creek
divestments; continued instability, or further deterioration, in
global economic and market environment, including from COVID-19
and/or inflation; the continued high commodity price environment,
or further volatility or a decline in commodity prices; changes in
realized prices of Enerplus' products from those currently
anticipated; changes in the demand for or supply of Enerplus'
products; unanticipated operating results, results from our capital
spending activities or production declines; legal proceedings or
other events inhibiting or preventing operation of 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;
risks associated with the realization of our deferred income tax
assets; 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 the Bank Credit
Facility, term loan and/or 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 identified in this news
release, the Annual Information Form, the Annual MD&A and Form
40-F as at December 31,
2020).
The forward-looking information contained in this news
release speaks 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, Enerplus uses the terms "adjusted funds
flow", "adjusted net income", "free cash flow", "reinvestment
rate", "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. "Reinvestment rate" is calculated as exploration
and development capital spending divided by adjusted funds flow.
"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", "reinvestment rate", "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 Third 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