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 2017
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. 9, 2017 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to
announce its third quarter 2017 operating and financial results.
The Company reported third quarter 2017 net income of $16.1 million, or $0.07 per share. This compares to a third quarter
2016 net loss of $100.7 million, or
$0.42 per share.
HIGHLIGHTS
- On track to deliver full-year 2017 and fourth quarter liquids
production targets
- 2017 capital spending guidance unchanged at $450 million
- Produced 33,300 BOE per day (85% oil) in October 2017 from North
Dakota, up 60% since the first quarter of 2017
- Ten wells brought on-stream in North
Dakota during the third quarter with average peak 30-day
production rates per well of 1,890 BOE per day, including the
Smooth Green well with a peak 30-day production rate of 3,317 BOE
per day
- Realized Bakken differential below WTI averaged US$3.24 per barrel in the third quarter;
expecting further improvement to US$2.00 per barrel in the fourth quarter
- Generated adjusted funds flow of $90.4
million
"Our plan for 2017 remains on track and on budget to drive
high-return crude oil production and associated cash flow growth
from our top tier North Dakota
position," stated Ian C. Dundas,
President and Chief Executive Officer. "Our strategy of allocating
capital to deliver sustainable, profitable cash flow growth
continues to enhance our already strong financial position, giving
us the flexibility and resiliency to continue to create long-term
value for shareholders."
THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Third quarter 2017 production averaged 79,128 BOE per day,
including 38,926 barrels per day of crude oil and natural gas
liquids. Liquids production for the third quarter was 5% lower than
the prior quarter primarily due to the divestment of the Brooks
waterflood property which closed in the second quarter, and a
completions program in North
Dakota weighted to the end of the quarter (approximately 70%
of third quarter net completions occurred in September). The
Company is on track to drive strong fourth quarter oil volumes with
North Dakota production in October
averaging 33,300 BOE per day (85% oil), compared to 27,210 BOE
per day in the third quarter. Total Company liquids production in
October averaged 44,600 barrels per day.
Enerplus remains well positioned relative to its full-year 2017
and fourth quarter liquids production targets. The Company has
updated its full-year 2017 liquids production guidance to 40,500
barrels per day (from 39,500 to 41,500 barrels per day) and
narrowed its fourth quarter liquids production guidance range to
45,000 to 46,000 barrels per day (from 43,000 to 48,000 barrels per
day).
Natural gas production for the third quarter averaged 241 MMcf
per day, 11% lower than the prior quarter primarily due to the
divestment of Canadian shallow gas properties which closed in the
second quarter, and price related production curtailments in the
Marcellus during September. Enerplus curtailed approximately 25
MMcf per day of its Marcellus natural gas production during
September and approximately 35 MMcf per day in October due to
unfavourable prices in the daily cash market. Since early November,
regional pricing has improved and the Company has returned to
producing at an unrestricted rate of approximately 200 MMcf per day
in the Marcellus. Although Enerplus anticipates stronger
Marcellus pricing in November and December, the Company remains
committed to focusing on value and therefore there may be
further curtailment in the event prices weaken during the
remainder of the fourth quarter.
As a result of the Marcellus curtailments in September and
October, Enerplus has revised its total annual average production
guidance for 2017 to 84,000 BOE per day (from 84,000 to 86,000 BOE
per day) and its fourth quarter production guidance range to 86,000
to 88,000 BOE per day (from 86,000 to 91,000 BOE per day). This
guidance assumes no further Marcellus production curtailments in
the fourth quarter. Total Company production in October averaged
82,700 BOE per day.
Enerplus generated adjusted funds flow of $90.4 million in the third quarter, compared to
$114.2 million in the previous
quarter. The quarter-over-quarter reduction was primarily due to
wider natural gas differentials and the strengthening of the
Canadian dollar in the third quarter. Tighter Bakken differentials
and lower transportation costs in the third quarter partially
offset the reduction in adjusted funds flow.
Exploration and development capital spending in the third
quarter was $119.1 million associated
with drilling, completing, and bringing 10.3 net wells on
production. The Company's 2017 exploration and development capital
budget of $450 million is
unchanged.
Enerplus' realized Bakken crude oil price differential averaged
US$3.24 per barrel below WTI in the
third quarter, an improvement of US$2.19 per barrel relative to the previous
quarter. Spot Bakken prices strengthened considerably throughout
the quarter due to the improved egress capacity from the Bakken,
on-going Canadian synthetic supply outages, and incremental demand
from refineries for light barrels due to on-going market disruption
during an active hurricane season. Accordingly, Enerplus is
narrowing its expected realized Bakken differential to US$2.00 per barrel below WTI for the fourth
quarter and its full-year differential to approximately
US$4.00 per barrel below WTI.
Enerplus' realized Marcellus natural gas sales price
differential widened to US$1.02 per
Mcf below NYMEX in the third quarter compared to US$0.64 per Mcf below NYMEX in the previous
quarter. Enerplus' transportation and sales contracts and its fixed
basis hedges moderated the weakness as the benchmark monthly
Transco Leidy price widened to average US$1.29 per Mcf below NYMEX during the quarter.
Marcellus pricing weakened during the quarter due to cooler than
average weather in the northeast United
States combined with incremental supply coming on-stream
during the quarter in expectation of flowing on the subsequently
delayed Rover Pipeline. Additional Marcellus pipeline capacity is
being brought on-line during the fourth quarter of 2017,
including partial capacity of Rover, which is expected to be at
full capacity towards the end of the first quarter of 2018.
Although pricing strengthened in early November, Marcellus
pricing remained weak in October with Transco Leidy daily prices
averaging US$0.76 per Mcf. Enerplus
is widening its full year 2017 Marcellus realized differential
guidance to US$0.80 per Mcf below
NYMEX (from US$0.75 per Mcf), and
estimates its fourth quarter realized differential will average
approximately US$1.05 per Mcf below
NYMEX.
Third quarter operating expenses averaged $6.71 per BOE, 15% higher compared to the prior
quarter. Operating expenses increased in the third quarter
primarily due to lower Marcellus production relative to the
previous quarter and higher gas facility charges and well servicing
costs on the Company's oil properties. As a result of the
impact of the Marcellus curtailment in September and October,
Enerplus is increasing its full-year 2017 operating
expenses to $6.50 per BOE, from
$6.40 per BOE. This increase to
operating expense guidance is more than offset by reductions in per
BOE transportation and cash G&A guidance, noted below.
Transportation costs in the third quarter averaged $3.61 per BOE, a decrease from $3.72 per BOE in the second quarter of 2017.
Transportation costs decreased in the third quarter due to lower
Marcellus production relative to the previous quarter and a
stronger Canadian dollar. Enerplus is reducing its 2017 guidance
for transportation costs to $3.70 per
BOE, from $3.90 per BOE.
Cash G&A expenses were $1.61
per BOE for the quarter, compared to $1.53 per BOE in the previous quarter. The modest
increase in cash G&A on a BOE basis was due to lower production
volumes relative to the previous quarter. Total cash G&A of
approximately $11.7 million was
broadly flat to the prior quarter. Enerplus is reducing its cash
G&A expense guidance to $1.70 per
BOE from $1.75 per BOE.
Enerplus remains in a strong financial position. Total debt net
of cash at September 30, 2017 was
$318.3 million. Total debt was
comprised of $667.3 million of senior
notes outstanding. The Company was undrawn on its $800 million bank credit facility, and had a cash
balance of $349.0 million. At
September 30, 2017, Enerplus' net
debt to adjusted funds flow ratio was 0.7 times.
AVERAGE DAILY PRODUCTION(1)
|
Three months ended
September 30,
2017
|
|
Nine months ended
September 30,
2017
|
|
Oil &
NGL
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
|
Oil &
NGL
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
Williston
Basin
|
28.0
|
18.7
|
31.0
|
|
26.4
|
19.0
|
29.5
|
Marcellus
|
0.0
|
189.7
|
31.6
|
|
0.0
|
199.6
|
33.3
|
Canadian
Waterfloods(2)
|
10.1
|
8.7
|
11.6
|
|
11.4
|
14.1
|
13.7
|
Other(2)
|
0.8
|
24.2
|
4.9
|
|
1.1
|
35.1
|
6.9
|
Total
|
38.9
|
241.2
|
79.1
|
|
38.8
|
267.9
|
83.4
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Nine month figures
include volumes from Canadian properties that were divested during
the first six months of 2017.
|
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
|
Three months ended
September 30,
2017
|
|
Nine months ended
September 30,
2017
|
|
Operated
|
|
Non
Operated
|
|
Operated
|
|
Non
Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
10
|
8.6
|
|
1
|
0.0
|
|
29
|
23.4
|
|
2
|
0.5
|
Marcellus
|
0
|
0.0
|
|
15
|
0.7
|
|
0
|
0.0
|
|
42
|
3.8
|
Canadian
Waterfloods
|
0
|
0.0
|
|
0
|
0.0
|
|
6
|
6.0
|
|
0
|
0.0
|
Other
|
1
|
1.0
|
|
0
|
0.0
|
|
1
|
1.0
|
|
0
|
0.0
|
Total
|
11
|
9.6
|
|
16
|
0.7
|
|
36
|
30.4
|
|
44
|
4.3
|
(1)
|
Table may not add due
to rounding.
|
ASSET ACTIVITY
Williston Basin
Williston Basin production
averaged 30,981 BOE per day (90% liquids) during the third quarter
of 2017, 4% lower than the second quarter. This decrease was
expected due to a completions program in North Dakota weighted to the end of the third
quarter, in part a function of pad development. Third quarter
Williston Basin production was
comprised of 27,210 BOE per day in North
Dakota and 3,771 BOE per day in Montana.
In the third quarter, Enerplus brought on-stream 10 gross
operated wells (86% average working interest) across its acreage at
Fort Berthold with an average completed lateral length of 8,770
feet per well and average peak 30-day production rates per well of
1,890 BOE per day (77% oil, on a three-stream basis). Of note are
four-wells on the Snakes pad, located in the northwest of Enerplus'
Fort Berthold acreage position, a high productivity area. The four
wells had an average completed lateral length per well of 9,100
feet and average peak 30-day production rates per well of 2,185 BOE
per day (75% oil). The average proppant loading across the 10
operated completions in the quarter was 1,250 pounds per foot,
including two wells, Smooth Green (Snakes pad) and Crane
(Cranes pad), testing 2,000 pounds per foot. The Smooth Green and
Crane wells had peak 30-day production rates of 3,317 BOE per day
(75% oil) and 1,950 BOE per day (83% oil) respectively.
The Company drilled 10 gross operated wells (66% average working
interest) in the third quarter.
The strong 2017 production growth from North Dakota is set to continue in the fourth
quarter with October production from North Dakota averaging 33,300 BOE per day (85%
oil).
Marcellus
Marcellus production averaged 190 MMcf per day during the third
quarter, a reduction of 7% from the previous quarter primarily due
to price related curtailments of approximately 25 MMcf per day
during September. Fifteen gross non-operated wells (5% average
working interest) were brought on-stream during the quarter with an
average completed lateral length of 6,300 feet per well and average
peak 30-day production rates per well of 14.8 MMcf per day.
The Company participated in drilling 19 gross non-operated wells
(12% average working interest) during the third quarter.
Enerplus continued to curtail approximately 35 MMcf per day of
its Marcellus production in October due to unfavourable prices in
the daily cash market. Since early November, regional pricing has
improved and the Company has returned to producing at
an unrestricted rate of approximately 200 MMcf per
day.
Canadian Waterfloods
Canadian waterflood production averaged 11,588 BOE per day (87%
liquids) during the third quarter, a decrease of 12% from the
previous quarter primarily due to the divestment of the Brooks
property during the second quarter. Activity in the quarter was
largely focused on waterflood optimization and the continued
advancement of waterflood implementation at Ante Creek, where total
water injection has increased to 9,000 barrels of water per day,
with a target injection of approximately 12,000 barrels of water
per day by year-end.
2017 UPDATED GUIDANCE
Enerplus' updated 2017 guidance is summarized below.
|
|
|
Guidance
|
Capital
spending
|
$450
million
|
Average annual
production
|
84,000 BOE/d (from
84,000 – 86,000 BOE/d)
|
Q4 average
production
|
86,000 – 88,000 BOE/d
(from 86,000 – 91,000 BOE/d)
|
Average annual crude
oil and natural gas liquids production
|
40,500 bbls/d (from
39,500 – 41,500 bbls/d)
|
Q4 average crude oil
and natural gas liquids production
|
45,000 – 46,000
bbls/d (from 43,000 – 48,000 bbls/d)
|
Average royalty and
production tax rate
|
24%
|
Operating
expense
|
$6.50/BOE (from
$6.40/BOE)
|
Transportation
expense
|
$3.70/BOE (from
$3.90/BOE)
|
Cash G&A
expense
|
$1.70/BOE (from
$1.75/BOE)
|
2017
Differential/Basis Outlook (1)
|
|
Average U.S. Bakken
crude oil differential (compared to WTI crude oil):
|
US$(4.00)/bbl (from
US$(4.50)/bbl)
|
Q4 Average U.S.
Bakken crude oil differential (compared to WTI crude
oil):
|
US$(2.00)/bbl
|
Average Marcellus
natural gas sales price differential (compared to NYMEX natural
gas):
|
US$(0.80)/Mcf (from
US$(0.75)/Mcf)
|
Q4 Average Marcellus
natural gas sales price differential (compared to NYMEX natural
gas):
|
US$(1.05)/Mcf
|
(1) Excluding
transportation costs.
|
|
RISK MANAGEMENT
Enerplus continues to manage price risk through commodity
hedging. Using swaps and collar structures, Enerplus has an average
of 20,000 barrels per day of crude oil protected for the remainder
of 2017 (approximately 72% of forecast crude oil production at the
midpoint of annual average guidance, net of royalties),
approximately 19,500 barrels per day of crude oil protected in
2018, and 10,000 barrels per day of crude oil protected in
2019.
For natural gas, Enerplus has 50,000 Mcf per day protected for
the remainder of 2017 (approximately 25% of forecast natural gas
production at the midpoint of annual average guidance, net of
royalties) using collar structures. For 2018, Enerplus has 25,000
Mcf per day protected using collar structures.
Commodity
Hedging Detail (As at November 8, 2017)
|
|
WTI Crude
Oil
(US$/bbl) (1)
|
Nymex Natural
Gas (US$/Mcf)
(1)
|
|
Oct 1, –
Dec 31,
2017
|
Jan 1, –
Mar 31,
2018
|
Apr 1 –
Jun 30,
2018
|
Jul 1 –
Sep 30,
2018
|
Oct 1 –
Dec 31,
2018
|
Jan 1, –
Mar 31,
2019
|
Apr 1, –
Dec 31,
2019
|
Oct 1, 2017
–
Dec 31,
2017
|
Jan 1, 2018
–
Dec 31,
2018
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
|
Sold Swaps
|
$53.50
|
$53.73
|
$53.73
|
$53.73
|
$53.73
|
$53.73
|
-
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
2,000
|
3,000
|
3,000
|
3,000
|
3,000
|
3,000
|
-
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
|
|
|
|
Sold Puts
|
$39.62
|
$42.83
|
$42.92
|
$42.71
|
$42.74
|
$43.54
|
$43.48
|
$2.06
|
-
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
15,000
|
18,000
|
20,000
|
7,000
|
10,000
|
50,000
|
-
|
|
|
|
|
|
|
|
|
|
|
Purchased
Puts
|
$50.61
|
$53.04
|
$52.90
|
$52.53
|
$52.48
|
$53.21
|
$53.53
|
$2.75
|
$2.75
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
15,000
|
18,000
|
20,000
|
7,000
|
10,000
|
50,000
|
25,000
|
|
|
|
|
|
|
|
|
|
|
Sold Calls
|
$60.33
|
$61.99
|
$61.73
|
$61.22
|
$61.10
|
$61.14
|
$62.27
|
$3.41
|
$3.46
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
15,000
|
18,000
|
20,000
|
7,000
|
10,000
|
50,000
|
25,000
|
(1)
|
Based on
weighted average price (before premiums). A portion of the sold
puts are settled annually rather than monthly.
|
Q3 2017 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:
|
Thursday, November 9,
2017
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
647-427-7450
|
|
1-888-231-8191 (toll
free)
|
Audiocast:
|
http://event.on24.com/r.htm?e=1516988&s=1&k=20AE8FC7B0697879EF594B0CE2E9A824
|
To ensure timely participation in the conference call, callers
are encouraged to dial in 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
Dial-In:
|
416-849-0833
|
|
1-855-859-2056 (toll
free)
|
Passcode:
|
92669366
|
SELECTED FINANCIAL AND OPERATING RESULTS
|
Three months ended September
30,
|
|
Nine months ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
16,131
|
|
$
|
(100,689)
|
|
$
|
221,726
|
|
$
|
(442,909)
|
Adjusted Funds
Flow(4)
|
|
90,386
|
|
|
80,101
|
|
|
324,505
|
|
|
197,875
|
Dividends to
Shareholders
|
|
7,264
|
|
|
7,214
|
|
|
21,769
|
|
|
28,225
|
Debt Outstanding –
net of Cash
|
|
318,273
|
|
|
654,071
|
|
|
318,273
|
|
|
654,071
|
Capital
Spending
|
|
119,102
|
|
|
60,277
|
|
|
341,188
|
|
|
151,673
|
Property and Land
Acquisitions
|
|
2,222
|
|
|
3,777
|
|
|
9,471
|
|
|
7,674
|
Property
Divestments
|
|
(1,361)
|
|
|
111
|
|
|
57,581
|
|
|
280,614
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.7x
|
|
|
2.2x
|
|
|
0.7x
|
|
|
2.2x
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
0.07
|
|
$
|
(0.42)
|
|
$
|
0.92
|
|
$
|
(2.00)
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
242,129
|
|
|
240,483
|
|
|
241,854
|
|
|
221,843
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$
|
33.23
|
|
$
|
27.20
|
|
$
|
35.21
|
|
$
|
23.69
|
Royalties and
Production Taxes
|
|
(7.98)
|
|
|
(6.20)
|
|
|
(8.28)
|
|
|
(5.20)
|
Commodity Derivative
Instruments
|
|
0.40
|
|
|
1.17
|
|
|
0.51
|
|
|
2.75
|
Cash Operating
Expenses
|
|
(6.73)
|
|
|
(6.64)
|
|
|
(6.39)
|
|
|
(7.33)
|
Transportation
Costs
|
|
(3.61)
|
|
|
(3.39)
|
|
|
(3.74)
|
|
|
(3.05)
|
Cash General and
Administrative Expenses
|
|
(1.61)
|
|
|
(1.58)
|
|
|
(1.67)
|
|
|
(1.79)
|
Cash Share-Based
Compensation
|
|
(0.10)
|
|
|
(0.03)
|
|
|
(0.04)
|
|
|
(0.07)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(1.17)
|
|
|
(1.07)
|
|
|
(1.25)
|
|
|
(1.37)
|
Current Income Tax
Recovery/(Expense)
|
|
(0.01)
|
|
|
(0.01)
|
|
|
(0.10)
|
|
|
0.01
|
Adjusted Funds
Flow(4)
|
$
|
12.42
|
|
$
|
9.45
|
|
$
|
14.25
|
|
$
|
7.64
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
35,245
|
|
|
37,717
|
|
|
35,102
|
|
|
38,764
|
Natural Gas Liquids
(bbls/day)
|
|
3,681
|
|
|
4,881
|
|
|
3,659
|
|
|
5,067
|
Natural Gas
(Mcf/day)
|
|
241,212
|
|
|
296,876
|
|
|
267,852
|
|
|
304,150
|
Total
(BOE/day)
|
|
79,128
|
|
|
92,077
|
|
|
83,403
|
|
|
94,523
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
49%
|
|
|
46%
|
|
|
46%
|
|
|
46%
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
$
|
54.21
|
|
$
|
47.93
|
|
$
|
55.75
|
|
$
|
41.92
|
Natural Gas Liquids
(per bbl)
|
|
26.22
|
|
|
13.85
|
|
|
29.09
|
|
|
13.53
|
Natural Gas (per
Mcf)
|
|
2.58
|
|
|
2.12
|
|
|
3.26
|
|
|
1.79
|
(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
|
2017
|
2016
|
|
2017
|
2016
|
WTI crude oil
(US$/bbl)
|
$
|
48.20
|
$
|
44.94
|
|
$
|
49.47
|
$
|
41.33
|
AECO natural gas–
monthly index (CDN$/Mcf)
|
|
2.04
|
|
2.20
|
|
|
2.58
|
|
1.85
|
AECO natural gas –
daily index (CDN$/Mcf)
|
|
1.45
|
|
2.32
|
|
|
2.31
|
|
1.85
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
3.00
|
|
2.81
|
|
|
3.17
|
|
2.29
|
USD/CDN average
exchange rate
|
|
1.25
|
|
1.31
|
|
|
1.31
|
|
1.32
|
Share Trading
Summary
|
CDN
(1) - ERF
|
U.S. (2) - ERF
|
For the three
months ended September 30, 2017
|
(CDN$)
|
(US$)
|
High
|
$
|
12.58
|
$
|
10.21
|
Low
|
$
|
9.75
|
$
|
7.55
|
Close
|
$
|
12.31
|
$
|
9.87
|
(1) TSX and
other Canadian trading data combined.
|
|
|
|
|
(2) NYSE and
other U.S. trading data combined.
|
|
|
|
|
2017 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. In order 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.
Readers are cautioned that the average initial production
rates contained in this news release are not necessarily indicative
of long-term performance or of ultimate recovery.
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", "should", "believe", "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 average
production volumes in 2017 and the anticipated production mix; the
portion of Marcellus production that is curtailed; the proportion
of anticipated oil and gas production that is hedged and the
effectiveness of such hedges in protecting funds flow; the results
from the drilling program and the timing of related production; oil
and natural gas prices and differentials and commodity risk
management programs in 2017, 2018, and beyond; expectations
regarding realized oil and natural gas prices; future royalty rates
on production and future production taxes; anticipated cash and
non-cash G&A, share-based compensation and financing expenses;
operating and transportation costs; capital spending levels in 2017
and its impact on production levels and land holdings; future
royalty and production and cash taxes; future debt and working
capital levels and debt to funds flow ratios.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: that
Enerplus will conduct its operations and achieve results of
operations as anticipated; that Enerplus' development plans will
achieve the expected results; current commodity price 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 Enerplus' reserves and resources volumes; the
continued availability of adequate debt and/or equity financing,
cash flow and other sources to fund Enerplus' capital and operating
requirements, and dividend payments, as needed; availability of
third party services; and the extent of its liabilities. In
addition, our updated 2017 guidance contained in this news release
is based on the following prices for the rest of the year: a WTI
price of US$50.00/bbl, a NYMEX price
of US$3.00/Mcf, an AECO price of
$2.00/GJ and a USD/CDN exchange rate
of 1.28. 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: changes,
including continued volatility, in commodity prices; changes in
realized prices for Enerplus' products; changes in the demand for
or supply of Enerplus' products; unanticipated operating results,
results from Enerplus' capital spending activities or production
declines; curtailment of Enerplus' 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 development plans by Enerplus or by third party
operators of Enerplus' properties; increased debt levels or debt
service requirements; Enerplus' inability to comply with covenants
under its bank credit facility and senior notes; changes in
estimates of Enerplus' oil and gas reserves and resources 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; failure to complete
any anticipated acquisitions or divestitures; and certain other
risks detailed from time to time in Enerplus' public disclosure
documents (including, without limitation, those risks identified in
its Annual Information Form, management's discussion and analysis
for the year-ended December 31, 2016,
and Form 40-F at December 31,
2016).
The forward-looking information contained in this press
release speak only as of the date of this press 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"
and "net debt to adjusted funds flow ratio" as 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. "Net debt to adjusted funds
flow ratio" is calculated as total debt net of cash and restricted
cash, divided by a trailing 12 months of adjusted funds flow.
Calculation of these terms is described in Enerplus' MD&A under
the "Liquidity and Capital Resources" section.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow"
and "net debt to adjusted funds flow" are useful supplemental
measures as they provide an indication of the results generated by
Enerplus' principal business activities. However, these measures
are not measures recognized by U.S. GAAP and do not have a
standardized meaning prescribed by U.S. GAAP. Therefore, these
measures, as defined by Enerplus, may not be comparable to similar
measures presented by other issuers. For reconciliation of these
measures to the most directly comparable measure calculated in
accordance with U.S. GAAP, and further information about these
measures, see disclosure under "Non-GAAP Measures" in Enerplus'
Third Quarter 2017 MD&A.
Electronic copies of Enerplus Corporation's Third Quarter 2017
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