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 2019
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, Nov. 8, 2019 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported
its third quarter 2019 operating and financial results. Cash flow
from operating activities for the third quarter was $159.8 million and adjusted funds flow was
$175.3 million. Third quarter net
income was $65.2 million, or
$0.28 per share, and adjusted net
income was $61.9 million, or
$0.27 per share.
HIGHLIGHTS
- Third quarter total production was 107,181 BOE per day, up 6%
quarter-over-quarter
- Third quarter liquids production was 60,121 barrels per day, up
14% quarter-over-quarter
- 2019 production guidance tightened to 100,000 to 101,000 BOE
per day (from 99,000 to 102,000 BOE per day) with liquids
production of 54,250 to 54,750 barrels per day (from 54,000 to
55,500 barrels per day)
- Third quarter capital spending was $151.5 million; 2019 capital spending guidance
is now $625 million (from
$610 to $630
million)
- Repurchased 7.1 million shares during the third quarter for
$64.8 million
- Since initiating its share repurchase program, Enerplus has
repurchased 24.2 million shares, or approximately 10% of shares
outstanding
- Maintained strong financial flexibility; ended the third
quarter with a net debt to adjusted funds flow ratio of 0.7
times
"In the third quarter of 2019, we continued to build on our
track record of strong execution and financial discipline," stated
Ian C. Dundas, President and Chief
Executive Officer. "We grew our high-return production in
North Dakota by 18%
quarter-over-quarter, maintained our focus on costs, and returned
over $70 million to shareholders
through share repurchases and dividends. Year to date, we have now
returned approximately $200 million
to shareholders. Our 2019 plan remains on track to deliver 9 to 10%
annual liquids production growth and 15% on a per share basis,
while maintaining our low financial leverage."
THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Production
Production in the third quarter increased
by 6% from the prior quarter to average 107,181 BOE per day,
including oil and natural gas liquids production of 60,121 barrels
per day, an increase of 14% from the prior quarter. The sequential
production growth was driven by North
Dakota volumes which increased 18% from the prior quarter.
Natural gas production decreased 2% quarter-over-quarter, averaging
282 MMcf per day.
Capital activity in the fourth quarter is expected to be
approximately 30% lower compared to the third quarter and will be
primarily related to drilling in North
Dakota. Enerplus expects modestly lower sequential
production in the fourth quarter and is providing fourth quarter
production guidance of 103,000 to 107,000 BOE per day with liquids
production of 58,000 to 60,000 barrels per day.
Adjusted Funds Flow and Adjusted Net Income
Adjusted
funds flow for the third quarter was $175.3
million compared to $186.0
million in the previous quarter. Third quarter 2019 adjusted
net income was $61.9 million
($0.27 per share) compared to
$74.3 million ($0.32 per share) in the previous quarter.
Pricing Realizations and Cost Structure
Enerplus'
third quarter 2019 realized Bakken oil price differential was
US$3.61 per barrel below WTI, 20%
weaker compared to the prior quarter. With wider Bakken oil
differentials expected to persist through the fourth quarter,
Enerplus is revising its full-year Bakken differential guidance to
US$3.60 per barrel below WTI (from
US$3.25 per barrel below WTI). The
Company continues to manage differential risk through fixed
physical sales and in the fourth quarter has 24,800 barrels per day
of Bakken oil production sold at US$2.69 per barrel below WTI.
The Company's realized Marcellus natural gas price differential
averaged US$0.44 per Mcf below NYMEX
during the third quarter, a 23% improvement from the prior quarter.
Enerplus is maintaining its full-year 2019 Marcellus differential
guidance at US$0.35 per Mcf below
NYMEX.
Third quarter operating expenses were $7.06 per BOE, transportation expenses were
$3.96 per BOE and cash G&A
expenses were $1.19 per BOE.
Combined, these expenses were 7% lower compared to the previous
quarter. Enerplus is reducing its full-year 2019 guidance for cash
G&A expenses to $1.40 per BOE
(from $1.45 per BOE).
Capital Expenditures and Balance Sheet
Position
Exploration and development capital spending in the
third quarter was $151.5 million and
was associated with drilling 16.9 net wells and bringing 13.3 net
wells on production across the Company's operations. Enerplus has
revised its full-year 2019 capital spending guidance to
$625 million (from $610 to $630
million).
At the end of the third quarter, Enerplus had total debt of
$618.4 million, cash of $97.0 million and was undrawn on its $800 million bank credit facility. The Company's
net debt to adjusted funds flow ratio was 0.7 times. Subsequent to
the quarter, Enerplus renewed its bank credit facility to
October 31, 2023 and amended it to a
U.S. dollar denominated facility of US$600
million.
Share Repurchases
The Company repurchased 7.1 million shares during the third
quarter for total consideration of $64.8
million. Subsequent to the quarter and up to November 6, 2019, the Company repurchased 2.7
million shares for a total consideration of $23.6 million and has now repurchased the maximum
number of shares under its existing NCIB (7% of the public float
within the meaning under the TSX rules). Enerplus today announced
that its Board of Directors has approved an increase to the maximum
number of shares that may be repurchased under the NCIB to 10% of
the public float, representing an additional 7.1 million shares,
until the expiry of its NCIB on March 25,
2020. Enerplus will continue to evaluate future share
repurchases as a function of the value and returns underpinning the
investment, alternative capital allocation opportunities and the
Company's financial capacity.
Since initiating its share repurchase program in the third
quarter of 2018 up to and including November
6, 2019, the Company has repurchased and cancelled 24.2
million shares, representing approximately 10% of shares
outstanding, for total consideration of $257.8 million.
ASSET ACTIVITY
Average Daily Production(1)
|
Three months
ended September 30, 2019
|
|
Nine months
ended September 30, 2019
|
|
Crude Oil
(Mbbl/d)
|
Natural
Gas
Liquids
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
|
Crude Oil
(Mbbl/d)
|
Natural Gas
Liquids
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
Williston
Basin
|
45.7
|
4.2
|
29.1
|
54.8
|
|
38.7
|
3.8
|
27.0
|
46.9
|
Marcellus
|
-
|
-
|
227.6
|
37.9
|
|
-
|
-
|
224.7
|
37.4
|
Canadian
Waterfloods
|
8.4
|
0.1
|
3.8
|
9.2
|
|
8.6
|
0.1
|
3.6
|
9.3
|
Other(2)
|
0.8
|
0.8
|
21.9
|
5.3
|
|
0.9
|
0.9
|
20.8
|
5.3
|
Total
|
55.0
|
5.1
|
282.4
|
107.2
|
|
48.1
|
4.7
|
276.1
|
98.9
|
(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, 2019
|
|
Nine months
ended September 30, 2019
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston
Basin
|
17
|
14.9
|
|
4
|
1.6
|
|
43
|
37.2
|
|
7
|
2.7
|
Marcellus
|
-
|
-
|
|
6
|
0.4
|
|
-
|
-
|
|
23
|
0.9
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
5
|
4.4
|
|
2
|
0.5
|
Total
|
17
|
14.9
|
|
10
|
2.0
|
|
49
|
42.6
|
|
32
|
4.1
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended September 30, 2019
|
|
Nine months
ended September 30, 2019
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston
Basin
|
11
|
8.0
|
|
1
|
0.1
|
|
40
|
34.3
|
|
5
|
2.0
|
Marcellus
|
-
|
-
|
|
13
|
0.9
|
|
-
|
-
|
|
40
|
4.3
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
Other(2)
|
5
|
4.4
|
|
-
|
-
|
|
5
|
4.4
|
|
2
|
0.5
|
Total
|
16
|
12.4
|
|
14
|
0.9
|
|
46
|
39.7
|
|
47
|
6.8
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Williston
Basin
Williston Basin
production averaged 54,800 BOE per day (83% oil) during the third
quarter of 2019, including 51,646 BOE per day in North Dakota (84% oil), an increase of 18%
from the prior quarter. The Company drilled 17 gross operated wells
(88% average working interest) and brought 11 gross operated wells
(72% average working interest) on production during the third
quarter.
Marcellus
Marcellus production averaged 228 MMcf per
day during the third quarter, down 2% from the previous quarter.
The Company participated in drilling six gross non-operated wells
(6% average working interest) and brought 13 gross non-operated
wells (7% average working interest) on production during the
quarter.
DJ Basin
Enerplus brought five gross operated wells
(88% average working interest) on production in the third quarter
in the DJ Basin. The Company continued to vary its completion
design on these wells utilizing both higher and lower proppant and
fluid intensities, aiming to further understand the associated well
performance and cost structures. Enerplus is encouraged by the
early stage production performance of the wells which are in line
with the Company's expectations.
2019 GUIDANCE
The Company's updated guidance, with changes noted, is provided
in the table below.
2019
Guidance
|
|
Capital
spending
|
$625 million
(from $610 to $630 million)
|
Average annual
production
|
100,000 to 101,000
BOE/day (from 99,000 to 102,000 BOE/day)
|
Average annual crude
oil and natural gas liquids production
|
54,250 to 54,750
bbls/day (from 54,000 to 55,500 bbls/d)
|
Q4 average
production
|
103,000 to 107,000
BOE/day
|
Q4 average crude oil
and natural gas liquids production
|
58,000 to 60,000
bbls/d
|
Average royalty and
production tax rate
|
25%
|
Operating
expense
|
$7.90/BOE
|
Transportation
expense
|
$4.00/BOE
|
Cash G&A
expense
|
$1.40/BOE (from
$1.45/BOE)
|
2019 Full-Year
Differential/Basis Outlook (1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(3.60)/bbl (from
US$(3.25)/bbl)
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.35)/Mcf
|
(1)
|
Excluding
transportation costs.
|
PRICE RISK MANAGEMENT
Enerplus continues to manage price risk through commodity
hedging. Enerplus has an average of 24,500 barrels per day of crude
oil protected for the remainder of 2019 and 16,000 barrels per day
protected in 2020.
For natural gas, Enerplus has entered into offsetting swaps
through October 31, 2019, effectively
locking in gains of US$0.51 per Mcf
on the Company's original NYMEX hedges through this term.
Commodity Hedging Detail (As at November 6, 2019)
|
WTI Crude
Oil
(US$/bbl)(1)
|
NYMEX Natural
Gas
(US$/Mcf)
|
|
Oct 1 – Dec
31,
2019
|
Jan 1 – Dec
31,
2020
|
Oct 1 – Oct
31,
2019
|
Swaps
|
|
|
|
Sold Swaps
|
-
|
-
|
$2.85
|
Volume (bbls/d or
Mcf/d)
|
-
|
-
|
90,000
|
Purchased
Swaps
|
-
|
-
|
$2.34
|
Volume (bbls/d or
Mcf/d)
|
-
|
-
|
90,000
|
Three-Way
Collars
|
|
|
|
Sold Puts
|
$44.64
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
-
|
-
|
Purchased
Puts
|
$54.81
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
-
|
-
|
Sold Calls
|
$65.99
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
-
|
-
|
Put
Spreads
|
|
|
|
Sold Puts
|
-
|
$46.88
|
-
|
Volume (bbls/d or
Mcf/d)
|
-
|
16,000
|
-
|
Purchased
Puts
|
-
|
$57.50
|
-
|
Volume (bbls/d or
Mcf/d)
|
-
|
16,000
|
-
|
(1)
|
The total average
deferred premium on outstanding hedges is US$2.14/bbl from October
1, 2019 to December 31, 2020.
|
Q3 2019 CONFERENCE CALL DETAILS
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM
ET) today to discuss these results. Details of the
conference call are as follows:
|
|
Date:
|
Friday, November 8,
2019
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
Conference
ID:
|
30294000
|
Audiocast:
|
https://event.on24.com/wcc/r/2100379/B276E7CC02EFC7703F1C9F77C135DD36
|
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:
|
294000 #
|
SELECTED FINANCIAL AND OPERATING RESULTS
|
|
|
|
|
SELECTED FINANCIAL
RESULTS
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
65,181
|
|
$
|
86,923
|
|
$
|
169,423
|
|
$
|
128,964
|
Cash Flow from
Operating Activities
|
|
|
159,806
|
|
|
216,098
|
|
|
505,748
|
|
|
517,165
|
Adjusted Funds
Flow(4)
|
|
|
175,277
|
|
|
210,351
|
|
|
530,070
|
|
|
539,221
|
Dividends to
Shareholders - Declared
|
|
|
6,836
|
|
|
7,355
|
|
|
21,032
|
|
|
22,022
|
Total Debt Net of
Cash(4)
|
|
|
521,379
|
|
|
313,591
|
|
|
521,379
|
|
|
313,591
|
Capital
Spending
|
|
|
151,520
|
|
|
193,264
|
|
|
519,521
|
|
|
521,818
|
Property and Land
Acquisitions
|
|
|
13,344
|
|
|
1,702
|
|
|
18,280
|
|
|
16,366
|
Property
Divestments
|
|
|
(168)
|
|
|
(762)
|
|
|
9,899
|
|
|
6,026
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
|
0.7x
|
|
|
0.4x
|
|
|
0.7x
|
|
|
0.4x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income -
Basic
|
|
$
|
0.28
|
|
$
|
0.35
|
|
$
|
0.72
|
|
$
|
0.53
|
Net Income -
Diluted
|
|
|
0.28
|
|
|
0.35
|
|
|
0.71
|
|
|
0.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
|
228,908
|
|
|
245,235
|
|
|
234,403
|
|
|
244,659
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
|
231,529
|
|
|
250,957
|
|
|
237,399
|
|
|
250,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
|
$
|
40.75
|
|
$
|
52.32
|
|
$
|
43.02
|
|
$
|
48.03
|
Royalties and
Production Taxes
|
|
|
(10.80)
|
|
|
(13.39)
|
|
|
(10.86)
|
|
|
(12.03)
|
Commodity Derivative
Instruments
|
|
|
0.53
|
|
|
(2.68)
|
|
|
0.54
|
|
|
(1.32)
|
Cash Operating
Expenses
|
|
|
(7.06)
|
|
|
(6.80)
|
|
|
(7.83)
|
|
|
(7.01)
|
Transportation
Costs
|
|
|
(3.96)
|
|
|
(3.70)
|
|
|
(3.97)
|
|
|
(3.60)
|
Cash General and
Administrative Expenses
|
|
|
(1.19)
|
|
|
(1.35)
|
|
|
(1.32)
|
|
|
(1.49)
|
Cash Share-Based
Compensation
|
|
|
—
|
|
|
0.02
|
|
|
(0.02)
|
|
|
(0.09)
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(0.49)
|
|
|
(0.81)
|
|
|
(0.65)
|
|
|
(0.94)
|
Current Income Tax
Recovery/(Expense)
|
|
|
—
|
|
|
(0.01)
|
|
|
0.72
|
|
|
(0.01)
|
Adjusted Funds
Flow(4)
|
|
$
|
17.78
|
|
$
|
23.60
|
|
$
|
19.63
|
|
$
|
21.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED OPERATING
RESULTS
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
55,023
|
|
|
48,867
|
|
|
48,141
|
|
|
43,892
|
Natural Gas Liquids
(bbls/day)
|
|
|
5,098
|
|
|
4,563
|
|
|
4,736
|
|
|
4,487
|
Natural Gas
(Mcf/day)
|
|
|
282,360
|
|
|
260,591
|
|
|
276,063
|
|
|
259,629
|
Total
(BOE/day)
|
|
|
107,181
|
|
|
96,861
|
|
|
98,888
|
|
|
91,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
56%
|
|
|
55%
|
|
|
53%
|
|
|
53%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
|
$
|
67.76
|
|
$
|
83.98
|
|
$
|
69.64
|
|
$
|
78.58
|
Natural Gas Liquids
(per bbl)
|
|
|
5.97
|
|
|
25.95
|
|
|
13.97
|
|
|
28.85
|
Natural Gas (per
Mcf)
|
|
|
2.13
|
|
|
3.22
|
|
|
3.00
|
|
|
3.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
|
17
|
|
|
17
|
|
|
47
|
|
|
49
|
(1)
|
Non-cash amounts have
been excluded.
|
(2)
|
Based on Company
interest production volumes. See "Presentation of Production
Information" below.
|
(3)
|
Before transportation
costs, royalties, and commodity derivative instruments.
|
(4)
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
Average Benchmark
Pricing
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
WTI crude oil
(US$/bbl)
|
|
$
|
56.45
|
|
$
|
69.50
|
|
$
|
57.06
|
|
$
|
66.75
|
Brent (ICE) crude oil
(US$/bbl)
|
|
|
62.00
|
|
|
75.97
|
|
|
64.74
|
|
|
72.68
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
|
2.23
|
|
|
2.90
|
|
|
2.67
|
|
|
2.90
|
USD/CDN average
exchange rate
|
|
|
1.32
|
|
|
1.31
|
|
|
1.33
|
|
|
1.29
|
|
|
|
|
|
|
|
Share Trading
Summary
|
|
CDN(1) - ERF
|
|
U.S.(2) - ERF
|
For the three
months ended September 30, 2019
|
|
(CDN$)
|
|
(US$)
|
High
|
|
$
|
11.16
|
|
$
|
8.43
|
Low
|
|
$
|
7.32
|
|
$
|
5.50
|
Close
|
|
$
|
9.87
|
|
$
|
7.44
|
(1)
|
TSX and other
Canadian trading data combined.
|
(2)
|
NYSE and other
U.S. trading data combined.
|
|
|
|
|
|
|
|
2019 Dividends per Share
|
|
CDN$
|
|
US$(1)
|
First Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.02
|
Second Quarter
Total
|
|
|
0.03
|
|
$
|
0.02
|
Third Quarter
Total
|
|
|
0.03
|
|
|
0.02
|
Total Year to
Date
|
|
$
|
0.09
|
|
$
|
0.06
|
(1)
|
CDN$
dividends converted at the relevant foreign exchange rate on
the payment date.
|
Currency and Accounting Principles
All amounts in
this news release are stated in Canadian dollars unless otherwise
specified. All financial information in this news release has been
prepared and presented in accordance with U.S. GAAP, except as
noted below under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also
contains references to "BOE" (barrels of oil equivalent). Enerplus
has adopted the standard of six thousand cubic feet of natural gas
to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to
BOEs. BOEs may be misleading, particularly if used in isolation.
The foregoing conversion ratios are based on an energy equivalency
conversion method primarily applicable at the burner tip and do not
represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of oil as compared to natural gas
is significantly different from the energy equivalent of 6:1,
utilizing a conversion on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S.
GAAP oil and gas sales are generally presented net of royalties and
U.S. industry protocol is to present production volumes net of
royalties. Under Canadian industry protocol oil and gas sales and
production volumes are presented on a gross basis before deduction
of royalties. To continue to be comparable with its Canadian peer
companies, the summary results contained within this news release
presents Enerplus' production and BOE measures on a before royalty
company interest basis. 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.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking
information and statements ("forward-looking information") within
the meaning of applicable securities laws. The use of any of the
words "expect", "anticipate", "continue", "estimate", "guidance",
"ongoing", "may", "will", "project", "plans", "budget", "strategy"
and similar expressions are intended to identify forward-looking
information. In particular, but without limiting the foregoing,
this news release contains forward-looking information pertaining
to the following: expected fourth quarter and 2019 average
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 and the
timing of related production; oil and natural gas prices and
differentials and our commodity risk management program in 2019 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 G&A, share-based
compensation and financing expenses; expected operating and
transportation costs; our anticipated shares repurchases under
current and future normal course issuer bids; capital spending
levels in 2019 and impact thereof on our production levels and land
holdings; the amount of our future abandonment and reclamation
costs and asset retirement obligations; future environmental
expenses; our future royalty and production and U.S. cash taxes;
future debt and working capital levels and net debt to adjusted
funds flow ratio and adjusted payout ratio, financial capacity,
liquidity and capital resources to fund capital spending and
working capital requirements; our future acquisitions and
dispositions, expecting timing thereof and use of proceeds
therefrom; and the amount of future cash dividends that we may pay
to our shareholders.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: that we will
conduct our operations and achieve results of operations as
anticipated; 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; current commodity price, differentials and
cost assumptions; the general continuance of current or, where
applicable, assumed industry conditions; the continuation of
assumed tax, royalty and regulatory regimes; the accuracy of the
estimates of our reserve and contingent resource volumes; the
continued availability of adequate debt and/or equity financing and
adjusted funds flow to fund our capital, operating and working
capital requirements, and dividend payments as needed; the
continued availability and sufficiency of our adjusted funds flow
and availability under our bank credit facility to fund our working
capital deficiency; the availability of third party services; and
the extent of our liabilities. In addition, our updated 2019
guidance contained in this news release is based on the rest of the
year prices of: a WTI price of US$54.00/bbl, a NYMEX price of US$2.40/Mcf, and a USD/CDN exchange rate of 1.32.
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
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; 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 identified in our Annual Information Form, our Annual
MD&A and Form 40-F as at December
31, 2018).
The forward-looking information contained in this news
release speak only as of the date of this news release. Enerplus
does not undertake any obligation to publicly update or revise any
forward-looking information contained herein, except as required by
applicable laws.
NON-GAAP MEASURES
In this news release, we use the terms "adjusted funds flow",
"adjusted net income", "net debt to adjusted funds flow ratio" and
"total debt net of cash" as measures to analyze operating
performance, leverage and liquidity. "Adjusted funds flow" is
calculated as cash flow generated from operating activities but
before changes in non-cash operating working capital and asset
retirement obligation expenditures. "Adjusted net income" is
calculated as net income adjusted for unrealized derivative
instrument gain/loss, unrealized foreign exchange gain/loss, the
tax effect of these items and the impact of statutory changes to
the Company's corporate tax rate. "Net debt to adjusted funds flow
ratio" is calculated as total debt net of cash and cash
equivalents, divided by a trailing 12 months of adjusted funds
flow. "Total debt net of cash" is calculated as senior notes plus
any outstanding bank credit facility balance, minus cash and cash
equivalents. Calculation of these terms is described in Enerplus'
MD&A under the "Non-GAAP Measures" section.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow",
"adjusted net income", "net debt to adjusted funds flow", and
"total debt net of cash" are useful supplemental measures as they
provide an indication of the results generated by Enerplus'
principal business activities. However, these measures are not
measures recognized by U.S. GAAP and do not have a standardized
meaning prescribed by U.S. GAAP. Therefore, these measures, as
defined by Enerplus, may not be comparable to similar measures
presented by other issuers. For reconciliation of these measures to
the most directly comparable measure calculated in accordance with
U.S. GAAP, and further information about these measures, see
disclosure under "Non-GAAP Measures" in Enerplus' Third Quarter
2019 MD&A.
Electronic copies of Enerplus Corporation's Third Quarter 2019
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.
Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation