All financial information contained within this news release
has been prepared in accordance with U.S. GAAP, except as noted
under "Non-GAAP Measures". This news release includes
forward-looking statements and information within the meaning of
applicable securities laws. Readers are advised to review the
"Forward-Looking Information and Statements" at the conclusion of
this news release. A full copy of Enerplus' Second Quarter 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, Aug. 9, 2019 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported
its second quarter 2019 operating and financial results. Cash
flow from operating activities for the second quarter was
$237.0 million and adjusted funds
flow was $186.0 million. Second
quarter net income was $85.1 million,
or $0.36 per share, and adjusted net
income was $74.3 million, or
$0.32 per share.
HIGHLIGHTS
- Second quarter total production was 100,694 BOE per day, up 14%
quarter-over-quarter, exceeding the high-end of the Company's
guidance
-
- Liquids production was 52,861 barrels per day, up 16%
quarter-over-quarter
- North Dakota production was
43,822 BOE per day, up 22% quarter-over-quarter
- 2019 total production guidance increased to 99,000 to 102,000
BOE per day (from 97,000 to 101,000 BOE per day) and liquids
production guidance narrowed to 54,000 to 55,500 barrels per day
(from 53,500 to 56,000 barrels per day)
-
- 14% liquids production per share growth in 2019 at the guidance
midpoint
- 2019 capital spending guidance tightened to $610 to $630
million (from $590 to
$630 million)
- Returned approximately $115
million of capital to shareholders through dividends and
share repurchases year to date
- Based on current market conditions, Enerplus intends to
repurchase its full authorization under its normal course issuer
bid ("NCIB") equaling an additional 8.9 million shares as at
August 7, 2019. Once completed, this
would equate to a total of 24.2 million shares repurchased, or
approximately 10% of shares outstanding, since initiating the share
repurchase program in the third quarter of 2018
- Improved 2019 Bakken oil differential guidance to US$3.25 per barrel below WTI (from US$4.00 per barrel)
- Reduced 2019 unit cost guidance for operating expenses and
cash general & administrative ("G&A") expenses
- Maintained significant financial flexibility; total debt net of
cash was $359.0
million with a net debt to adjusted funds flow ratio of
0.5 times
President and Chief Executive Officer Ian C. Dundas commented: "We've established
strong operational momentum through the first half of the year and
remain well positioned relative to our financial and operational
targets in 2019. Our strategy continues to be underpinned by
disciplined capital allocation which is delivering profitable oil
production growth and return of capital to shareholders, while
maintaining our peer-leading balance sheet strength."
"Since initiating our share repurchase program in the third
quarter of 2018, we've returned over $175
million to shareholders through repurchases. Underlying this
decision has been the compelling value we see in our equity. We
continue to see this value in our shares today and remain committed
to prioritizing the acquisition of our stock, based on current
market conditions."
SECOND QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Production
Production in the second quarter increased
by 14% from the prior quarter to average 100,694 BOE per day,
including oil and natural gas liquids production of 52,861 barrels
per day (91% oil). The sequential production increase was driven by
North Dakota and Marcellus volumes
which were up 22% and 14%, respectively. With outperformance in the
Marcellus and continued strong production in North Dakota, Enerplus is increasing its
annual production guidance to 99,000 to 102,000 BOE per day (from
97,000 to 101,000 BOE per day) and narrowing its liquids production
guidance to 54,000 to 55,500 barrels per day (from 53,500 to 56,000
barrels per day).
North Dakota production is
expected to meaningfully build in the third quarter due to the
timing of several well completions late in the second quarter and
continued completions activity in the third quarter, with volumes
moderating into the fourth quarter.
During the second quarter, Enerplus closed divestments for
proceeds of $9.6 million primarily
related to the sale of properties in southeast Saskatchewan with associated production of
approximately 350 barrels per day (100% oil).
Adjusted Funds Flow and Adjusted Net Income
Second
quarter 2019 adjusted funds flow was $186.0
million compared to $168.8
million in the previous quarter. Second quarter adjusted
funds flow included a current tax recovery of $13.9 million. Second quarter 2019 adjusted net
income was $74.3 million
($0.32 per share) compared to
$72.5 million ($0.30 per share) in the previous quarter.
Pricing Realizations and Cost Structure
Enerplus'
realized Bakken oil price differential averaged US$3.00 per barrel below WTI in the second
quarter. Based on year to date price realizations and the continued
strength in Bakken differentials, Enerplus is revising its full
year Bakken differential guidance to US$3.25 per barrel below WTI (from US$4.00 per barrel). The Company continues to
manage differential risk through fixed physical sales. For the
second half of 2019, Enerplus has fixed physical differential sales
of approximately 26,300 barrels per day of Bakken oil production at
US$2.66 per barrel below WTI,
including a portion which is sold directly into the U.S. Gulf Coast
that utilizes the Company's firm capacity on the Dakota Access
Pipeline. Enerplus' remaining production is sold through a
combination of in-basin monthly spot and index sales.
The Company's realized Marcellus natural gas price differential
moderated in the second quarter to US$0.57 per Mcf below NYMEX from the strong
pricing in the prior quarter. A significant portion of the
Company's Marcellus sales are tied to the Transco Zone 6
non-New York markets, where
seasonal changes in demand drive prices lower from winter to
spring. Enerplus is widening its full-year 2019 Marcellus
differential guidance to US$0.35 per
Mcf below NYMEX (from US$0.30 per
Mcf).
Second quarter operating expenses were $7.84 per BOE, transportation expenses were
$4.02 per BOE and cash G&A
expenses were $1.26 per BOE. Enerplus
is reducing its 2019 operating expense guidance to $7.90 per BOE (from $8.00 per BOE) and its cash G&A guidance to
$1.45 per BOE (from $1.50 per BOE) primarily due to the Company's
higher 2019 production expectations.
Capital Expenditures and Balance Sheet
Position
Exploration and development capital spending in the
second quarter was $207.2 million and
was associated with drilling 12.7 net wells and bringing 26.3 net
wells on production across the Company's operations. Enerplus has
narrowed its 2019 capital spending guidance to $610 to $630
million (from $590 to
$630 million) following the continued
optimization of its operational plans. Capital spending for the
second half of 2019 is expected to be weighted to the third
quarter.
The Company continues to maintain its significant financial
flexibility. At the end of the second quarter, its total debt net
of cash was $359.0 million and its
net debt to adjusted funds flow ratio was 0.5 times.
Share Repurchases
The Company repurchased and
cancelled 6.6 million shares during the second quarter for total
consideration of $70.6 million. Since
initiating its share repurchase program in the third quarter of
2018 up to and including August 7,
2019, the Company has repurchased and cancelled 15.3 million
shares for total consideration of $178
million.
Enerplus continues to see the current trading value of its
equity as discounted relative to the Company's internal view. As a
result, the Company intends to repurchase the remaining
authorization under its NCIB equaling an additional 8.9 million
shares as at August 7, 2019. Combined
with the shares repurchased to date, this would represent a total
of 24.2 million shares repurchased, or approximately 10% of shares
outstanding, since initiating its share repurchase program in the
third quarter of 2018. The Company's existing NCIB expires
March 25, 2020.
ASSET ACTIVITY
Average Daily Production(1)
|
Three months
ended June 30, 2019
|
|
Six months
ended June 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
|
38.8
|
3.7
|
26.6
|
46.9
|
|
35.1
|
3.5
|
25.9
|
42.9
|
Marcellus
|
-
|
-
|
237.3
|
39.5
|
|
-
|
-
|
223.2
|
37.2
|
Canadian
Waterfloods
|
8.4
|
0.1
|
3.9
|
9.2
|
|
8.6
|
0.1
|
3.5
|
9.3
|
Other(2)
|
0.9
|
0.9
|
19.2
|
5.0
|
|
1.0
|
0.9
|
20.2
|
5.2
|
Total
|
48.1
|
4.7
|
287.0
|
100.7
|
|
44.6
|
4.6
|
272.9
|
94.7
|
(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 June 30, 2019
|
|
Six months
ended June 30, 2019
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
26
|
23.3
|
|
3
|
1.4
|
|
29
|
26.3
|
|
4
|
1.9
|
Marcellus
|
-
|
-
|
|
14
|
1.6
|
|
-
|
-
|
|
27
|
3.5
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
2
|
0.5
|
Total
|
26
|
23.3
|
|
17
|
3.0
|
|
30
|
27.3
|
|
33
|
5.8
|
(1) Table may not add
due to rounding.
|
(2) Comprises DJ
Basin and non-core properties in Canada.
|
Williston
Basin
Williston Basin
production averaged 46,920 BOE per day (83% oil) during the second
quarter of 2019, including 43,822 BOE per day from North Dakota (83% oil). The Company drilled 11
gross operated wells (73% average working interest) and brought 26
gross operated wells (90% average working interest) on production
during the second quarter, including a nine-well pad at the end of
June.
Enerplus continues to drive capital efficiency improvements with
current well costs down approximately US$700,000 from 2018 levels driven by a
combination of lower costs, efficiencies and completion
optimization. Enerplus' current total well cost for a
two-mile lateral (drill, complete, tie-in and facilities) is
estimated at US$7.5 million.
Marcellus
Marcellus production averaged 237 MMcf per
day during the second quarter, 14% higher than the previous
quarter. The Company participated in drilling eight gross
non-operated wells (4% average working interest) and brought 14
gross non-operated wells (11% average working interest) on
production during the quarter.
DJ Basin
The Company drilled five gross operated wells
(88% average working interest) in the second quarter. These wells
are expected to be completed in the third quarter.
2019 Guidance Updates
The Company's updated guidance for 2019 is in the table below,
including changes from its previous guidance.
2019 Guidance
Capital
spending
|
$610 to
$630 million (from $590 to $630 million)
|
Average annual
production
|
99,000 to 102,000
BOE/day (from 97,000 to 101,000 BOE/day)
|
Average annual crude
oil and natural gas liquids production
|
54,000 to 55,500
bbls/day (from 53,500 to 56,000 bbls/d)
|
Average royalty and
production tax rate
|
25%
|
Operating
expense
|
$7.90/BOE (from
$8.00/BOE)
|
Transportation
expense
|
$4.00/BOE
|
Cash G&A
expense
|
$1.45/BOE (from
$1.50/BOE)
|
2019 Full-Year
Differential/Basis Outlook (1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(3.25)/bbl (from
US$(4.00)/bbl)
|
Marcellus natural gas
sales price differential (compared to NYMEX natural gas)
|
US$(0.35)/Mcf (from
US$(0.30)/Mcf)
|
(1) Excluding
transportation costs.
|
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 $0.51 per Mcf on
the Company's original NYMEX hedges through this term.
Commodity Hedging Detail (As at August 7, 2019)
|
|
|
|
|
WTI Crude
Oil (US$/bbl)
|
NYMEX Natural
Gas (US$/Mcf)
|
|
Jul 1, – Sep
30,
2019
|
Oct 1, – Dec
31,
2019
|
Jan 1, – Dec
31,
2020
|
Jul 1 – Jul
31,
2019
|
Aug 1 – Oct
31,
2019
|
Swaps
|
|
|
|
|
|
Sold Swaps
|
-
|
-
|
-
|
$2.85
|
$2.85
|
Volume (bbls/d or
Mcf/d)
|
-
|
-
|
-
|
90,000
|
90,000
|
|
|
|
|
|
|
Purchased
Swaps
|
-
|
-
|
-
|
$2.34
|
$2.34
|
Volume (bbls/d or
Mcf/d)
|
-
|
-
|
-
|
60,000
|
90,000
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
Sold Puts
|
$44.64
|
$44.64
|
-
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
24,500
|
-
|
-
|
-
|
|
|
|
|
|
|
Purchased
Puts
|
$54.81
|
$54.81
|
-
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
24,500
|
-
|
-
|
-
|
|
|
|
|
|
|
Sold Calls
|
$65.95
|
$65.99
|
-
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
24,500
|
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$2.00/bbl from
July 1, 2019 to December 31, 2020.
|
Q2 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, August 9,
2019
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
587-880-2171
(Alberta)
|
|
1-888-390-0546 (Toll
Free)
|
Conference
ID:
|
18883249
|
Audiocast:
|
https://event.on24.com/wcc/r/2040116/096536B9083B08C863107046B5B438D1
|
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:
|
883249 #
|
SELECTED FINANCIAL AND OPERATING RESULTS
SELECTED FINANCIAL
RESULTS
|
Three months
ended
June 30,
|
|
Six months
ended
June 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
$
|
85,084
|
|
$
|
12,404
|
|
$
|
104,242
|
|
$
|
42,041
|
Cash Flow from
Operating Activities
|
|
236,991
|
|
|
141,767
|
|
|
345,942
|
|
|
301,067
|
Adjusted Funds
Flow(4)
|
|
186,038
|
|
|
173,708
|
|
|
354,793
|
|
|
328,870
|
Dividends to
Shareholders - Declared
|
|
7,034
|
|
|
7,347
|
|
|
14,196
|
|
|
14,667
|
Total Debt Net of
Cash(4)
|
|
359,006
|
|
|
311,782
|
|
|
359,006
|
|
|
311,782
|
Capital
Spending
|
|
207,208
|
|
|
177,082
|
|
|
368,001
|
|
|
328,554
|
Property and Land
Acquisitions
|
|
1,911
|
|
|
2,392
|
|
|
4,936
|
|
|
14,664
|
Property
Divestments
|
|
9,601
|
|
|
(182)
|
|
|
10,067
|
|
|
6,788
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.5x
|
|
|
0.5x
|
|
|
0.5x
|
|
|
0.5x
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
Net Income -
Basic
|
$
|
0.36
|
|
$
|
0.05
|
|
$
|
0.44
|
|
$
|
0.17
|
Net Income -
Diluted
|
|
0.36
|
|
|
0.05
|
|
|
0.43
|
|
|
0.17
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
235,490
|
|
|
244,862
|
|
|
237,197
|
|
|
244,369
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
238,189
|
|
|
250,122
|
|
|
239,947
|
|
|
249,367
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$
|
44.00
|
|
$
|
48.13
|
|
$
|
44.33
|
|
$
|
45.65
|
Royalties and
Production Taxes
|
|
(11.26)
|
|
|
(12.08)
|
|
|
(10.90)
|
|
|
(11.28)
|
Commodity Derivative
Instruments
|
|
(0.13)
|
|
|
(2.28)
|
|
|
0.55
|
|
|
(0.57)
|
Cash Operating
Expenses
|
|
(7.84)
|
|
|
(7.21)
|
|
|
(8.26)
|
|
|
(7.12)
|
Transportation
Costs
|
|
(4.02)
|
|
|
(3.56)
|
|
|
(3.97)
|
|
|
(3.54)
|
Cash General and
Administrative Expenses
|
|
(1.26)
|
|
|
(1.44)
|
|
|
(1.39)
|
|
|
(1.57)
|
Cash Share-Based
Compensation
|
|
0.07
|
|
|
(0.05)
|
|
|
(0.04)
|
|
|
(0.16)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(0.79)
|
|
|
(0.95)
|
|
|
(0.75)
|
|
|
(0.99)
|
Current Income Tax
Recovery/(Expense)
|
|
1.52
|
|
|
(0.01)
|
|
|
1.14
|
|
|
(0.01)
|
Adjusted Funds
Flow(4)
|
$
|
20.29
|
|
$
|
20.55
|
|
$
|
20.71
|
|
$
|
20.41
|
SELECTED OPERATING
RESULTS
|
Three months
ended
June 30,
|
|
Six months
ended
June 30,
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
48,141
|
|
|
45,242
|
|
|
44,642
|
|
|
41,364
|
Natural Gas Liquids
(bbls/day)
|
|
4,720
|
|
|
4,808
|
|
|
4,552
|
|
|
4,449
|
Natural Gas
(Mcf/day)
|
|
287,000
|
|
|
256,995
|
|
|
272,863
|
|
|
259,141
|
Total
(BOE/day)
|
|
100,694
|
|
|
92,883
|
|
|
94,671
|
|
|
89,003
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
52%
|
|
|
54%
|
|
|
52%
|
|
|
51%
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
$
|
74.42
|
|
$
|
79.98
|
|
$
|
70.82
|
|
$
|
75.34
|
Natural Gas Liquids
(per bbl)
|
|
17.96
|
|
|
32.23
|
|
|
18.53
|
|
|
30.36
|
Natural Gas (per
Mcf)
|
|
2.63
|
|
|
2.68
|
|
|
3.46
|
|
|
3.09
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
13
|
|
|
18
|
|
|
30
|
|
|
32
|
(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
June 30,
|
|
Six months
ended
June 30,
|
Average Benchmark
Pricing
|
2019
|
|
2018
|
|
2019
|
|
2018
|
WTI crude oil
(US$/bbl)
|
$
|
59.81
|
|
$
|
67.88
|
|
$
|
57.36
|
|
$
|
65.37
|
Brent (ICE) crude oil
(US$/bbl)
|
|
68.32
|
|
|
74.90
|
|
|
66.11
|
|
|
71.04
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
2.64
|
|
|
2.80
|
|
|
2.89
|
|
|
2.90
|
USD/CDN average
exchange rate
|
|
1.34
|
|
|
1.29
|
|
|
1.33
|
|
|
1.28
|
|
|
|
|
|
|
Share Trading
Summary
|
CDN(1) - ERF
|
|
U.S.(2) - ERF
|
For the three
months ended June 30, 2019
|
(CDN$)
|
|
(US$)
|
High
|
$
|
13.10
|
|
$
|
9.74
|
Low
|
$
|
8.76
|
|
$
|
6.53
|
Close
|
$
|
9.85
|
|
$
|
7.53
|
(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
|
Total Year to
Date
|
|
$
|
0.06
|
|
$
|
0.04
|
(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 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$56.00/bbl, a NYMEX price of US$2.30/Mcf, and a USD/CDN exchange rate of 1.31.
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",
"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. "Net debt to adjusted funds flow ratio" is calculated
as total debt net of cash and cash equivalents, divided by a
trailing 12 months of adjusted funds flow. "Total debt net of cash"
is calculated as senior notes plus any outstanding bank credit
facility balance, minus cash and cash equivalents. Calculation of
these terms is described in Enerplus' MD&A under the "Non-GAAP
Measures" section.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow",
"net debt to adjusted funds flow", and "total debt net of cash" are
useful supplemental measures as they provide an indication of the
results generated by Enerplus' principal business activities.
However, these measures are not measures recognized by U.S. GAAP
and do not have a standardized meaning prescribed by U.S. GAAP.
Therefore, these measures, as defined by Enerplus, may not be
comparable to similar measures presented by other issuers. For
reconciliation of these measures to the most directly comparable
measure calculated in accordance with U.S. GAAP, and further
information about these measures, see disclosure under "Non-GAAP
Measures" in Enerplus' Second Quarter 2019 MD&A.
Electronic copies of Enerplus Corporation's Second 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