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 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, Aug. 11, 2017 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to
announce its second quarter 2017 operating and financial results.
The Company reported second quarter 2017 net income of $129.3 million, or $0.53 per share. This compares to a second
quarter 2016 net loss of $168.6
million, or $0.77 per
share.
SECOND QUARTER 2017 HIGHLIGHTS:
- 35% production growth in North
Dakota quarter-over-quarter
- Generated adjusted funds flow of $114.2
million
- Increasing 2017 production guidance to 84,000 – 86,000 BOE per
day
- 12% reduction in operating expenses quarter-over-quarter, 19%
reduction year-over-year
- Lowering operating, cash G&A, and transportation expense
guidance by a total of $0.65 per
BOE
"Our second quarter results demonstrate the oil production
growth potential of our high-quality position at Fort Berthold,
where we remain on track to deliver 50% production growth over the
course of 2017," stated Ian C.
Dundas, President and Chief Executive Officer.
"Additionally, our focus on cost management and commitment to
maintaining our strong financial footing continues to position
Enerplus to deliver sustained, long-term profitable growth in a
lower commodity price environment."
FINANCIAL AND OPERATIONAL SUMMARY
Second quarter 2017 production averaged 86,209 BOE per day,
including 40,994 barrels per day of crude oil and natural gas
liquids. Liquids production increased to 48% of total company
production, growing 13% from the first quarter driven by strong
North Dakota volumes. Operations
in North Dakota have been trending
ahead of schedule which, combined with continued strong well
performance, helped deliver second quarter North Dakota production of 28,047 BOE per day,
a 35% increase from the previous quarter.
Enerplus is increasing its 2017 annual average production
guidance range to 84,000 to 86,000 BOE per day (from 81,000 to
85,000 BOE per day) and its 2017 annual average liquids guidance to
39,500 to 41,500 barrels per day (from 38,500 to 41,500 barrels per
day).
During the second quarter, Enerplus closed the previously
announced divestment of shallow gas assets in Canada and its Brooks waterflood property with
combined production of approximately 5,600 BOE per day. Second
quarter production also included approximately 6 MMcf per day
related to a Marcellus gas balancing adjustment. Production in the
third quarter is expected to be sequentially lower due to this
divestment and the gas balancing adjustment, combined with fewer
wells planned to be brought on-stream in North Dakota and the Marcellus relative to the
second quarter. Production is expected to significantly build later
in the year with capital activity in the third quarter driving
strong volumes into the fourth quarter. Enerplus remains well
positioned to achieve its fourth quarter production guidance of
86,000 to 91,000 BOE per day including 43,000 to 48,000 barrels per
day of liquids.
Enerplus generated adjusted funds flow of $114.2 million, a 5% decrease from the previous
quarter as a result of lower commodity prices, which was offset by
strong liquids production growth out of North Dakota, and reduced operating and
G&A expenses during the quarter.
Exploration and development capital spending in the second
quarter of 2017 was $101.7 million,
with $70.7 million directed to
North Dakota, $9.9 million allocated to the Canadian
waterfloods, and $17.5 million
directed to the Marcellus. Enerplus' 2017 exploration and
development capital budget of $450
million is unchanged.
Enerplus' commodity hedging program realized cash gains of
$2.2 million for the second quarter
of 2017, compared to cash gains of $6.6
million in the first quarter of 2017.
Enerplus' realized Bakken crude oil price differential averaged
US$5.43 per barrel below WTI in the
second quarter, a 3% improvement relative to the previous quarter.
Spot Bakken prices strengthened considerably late in the second
quarter and into the third quarter as the Dakota Access Pipeline
was brought into service in June. Based on this ongoing strength in
pricing, Enerplus continues to expect its Bakken crude oil
differential to average approximately US$4.50 per barrel below WTI during 2017.
Enerplus' realized Marcellus natural gas sales price
differential widened slightly to US$0.64 per Mcf below NYMEX in the second quarter
compared to US$0.60 per Mcf in the
previous quarter. Regulatory issues announced in May have delayed
the construction of the Rover pipeline project that will transport
gas from the Marcellus/Utica
region into the U.S. Midwest and Eastern
Canada. Combined with higher production in the region
relative to the previous quarter, this delay weakened regional
market prices, pushing Marcellus basis differentials wider late in
the quarter. Considering the uncertainty in the timing of the
in-service date of the Rover pipeline, Enerplus now expects its
Marcellus natural gas realized price differential to average
US$0.75 per Mcf below NYMEX for 2017
(compared to US$0.60 per Mcf
previously). Enerplus expects its Marcellus price differentials
will continue to narrow once Rover and other pipeline projects
slated for completion in the second half of 2017 are in-service,
with a view to more consistent differentials and improved pricing
moving into 2018.
Second quarter operating expenses averaged $5.83 per BOE, 12% lower compared to the prior
quarter. Operating expenses continued to improve in the second
quarter largely due to additional savings from the 2017 divestment
program. As a result, Enerplus is lowering its 2017 operating
expense guidance to $6.40 per BOE,
from $6.85 per BOE. Enerplus expects
operating costs to increase over the remainder of 2017 as its
liquids production weighting increases.
Transportation costs in the second quarter averaged $3.72 per BOE, a decrease from $3.88 per BOE in the first quarter of 2017.
Enerplus is reducing its 2017 guidance for transportation costs to
$3.90 per BOE, from $4.00 per BOE, due to the impact of lower than
expected USD/CDN foreign exchange rates on U.S. transportation
costs and the increase in the Company's annual production
guidance.
Cash G&A expenses were $1.53
per BOE for the quarter, compared to $1.87 per BOE in the previous quarter. The
decrease in cash G&A expenses was due to continued cost savings
initiatives and the impact of reductions in staffing levels
following asset divestments during the year. Enerplus is reducing
its cash G&A expense guidance to $1.75 per BOE, from $1.85 per BOE.
Enerplus remains in a strong financial position. Total debt net
of cash at June 30, 2017 was
$308.1 million. Total debt was
comprised of $693.1 million of senior
notes outstanding. The Company was undrawn on its $800 million bank credit facility, and had a cash
balance of $385.1 million. At
June 30, 2017, Enerplus' net debt to
adjusted funds flow ratio was 0.7 times.
AVERAGE DAILY PRODUCTION(1)
|
Three months ended
June 30, 2017
|
|
Six months ended
June 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
|
28.9
|
19.9
|
32.2
|
|
25.5
|
19.1
|
28.7
|
Marcellus
|
0.0
|
204.7
|
34.1
|
|
0.0
|
204.7
|
34.1
|
Canadian
Waterfloods(2)
|
11.0
|
13.0
|
13.1
|
|
12.0
|
16.9
|
14.8
|
Other(2)
|
1.1
|
33.8
|
6.7
|
|
1.2
|
40.7
|
8.0
|
Total
|
41.0
|
271.3
|
86.2
|
|
38.7
|
281.4
|
85.6
|
(1)
|
Table may not add due to rounding.
|
(2)
|
Includes volumes from Canadian properties that were
divested during the first six months of 2017.
|
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
|
Three months ended
June 30, 2017
|
|
Six months ended
June 30, 2017
|
|
Operated
|
|
Non
Operated
|
|
Operated
|
|
Non
Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
11
|
8.1
|
|
1
|
0.5
|
|
19
|
14.8
|
|
1
|
0.5
|
Marcellus
|
0
|
0.0
|
|
13
|
2.3
|
|
0
|
0.0
|
|
27
|
3.1
|
Canadian
Waterfloods
|
3
|
3.0
|
|
0
|
0.0
|
|
5
|
5.0
|
|
0
|
0.0
|
Total
|
14
|
11.1
|
|
14
|
2.7
|
|
24
|
19.8
|
|
28
|
3.6
|
(1)
|
Table may not add due
to rounding.
|
ASSET ACTIVITY
Williston Basin
Williston Basin production
averaged 32,240 BOE per day (90% liquids) during the second quarter
of 2017, a 29% increase compared to the prior quarter. Second
quarter Williston Basin production
was comprised of 28,047 BOE per day in North Dakota, a 35% increase from the prior
quarter, and 4,193 BOE per day in Montana, approximately flat to the prior
quarter.
In the second quarter, Enerplus brought on-stream 11 gross
operated wells (74% average working interest) across its acreage at
Fort Berthold. Of note is the Arctic 94-36BH well which has
continued to produce at strong rates after three months on
production. The well has delivered a peak 90-day production rate of
1,250 BOE per day. This 4,300 foot lateral well was completed with
a proppant volume of approximately 2,300 pounds per foot, higher
than Enerplus' base completion design of 1,000 pounds per foot. Two
wells were brought on production from the Marsupials pad with an
average lateral length of 4,300 feet and an average peak 30-day
production rate per well of 1,318 BOE per day. Four wells on the
Mountains pad were brought on production with an average lateral
length of 9,300 feet and an average peak 30-day production rate per
well of 1,275 BOE per day.
The Company drilled 10 gross operated wells (85% average working
interest) in the second quarter, including a 20,000 ft. (10,000 ft.
lateral) well drilled in under 12 days from spud to rig release, a
new record for the Company. This represents an 18% improvement in
drilling days compared to the Company's previous fastest drill.
Marcellus
Marcellus production averaged 205 MMcf per day during the second
quarter of 2017, approximately flat to the previous quarter.
Production volumes in the quarter included approximately 6 MMcf per
day related to a gas balancing adjustment. Thirteen gross
non-operated wells (18% average working interest) were brought
on-stream during the second quarter of 2017. Twelve of these wells
had more than 30 days on production as of the date of this news
release with an average lateral length of 4,900 feet per well and
an average peak 30-day production rate per well of 13.2 MMcf per
day.
The Company participated in drilling 13 gross non-operated wells
(18% average working interest) during the second quarter.
Canadian Waterfloods
Canadian waterflood production averaged 13,144 BOE per day (83%
liquids) during the second quarter of 2017, a decrease of 20% from
the previous quarter primarily due to the divestment of the Brooks
property during the quarter. Activity in the quarter was largely
focused at Ante Creek with the continued advancement of waterflood
implementation across the field. Water injection has been increased
from 1,000 barrels of water per day in January 2017 to over 5,000 barrels of water per
day currently, with a target injection of 12,000 to 15,000 barrels
of water per day by year-end.
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, net of
royalties), 18,000 barrels per day of crude oil protected in 2018,
and 4,000 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 net of royalties) using collar structures.
Commodity Hedging
Detail (As at August 10, 2017)
|
|
WTI Crude
Oil
(US$/bbl) (1)
|
Nymex Natural
Gas (US$/Mcf)
(1)
|
|
Jul 1, 2017 –
Dec 31, 2017
|
Jan 1, 2018 –
Jun 30, 2018
|
Jul 1, 2018 –
Dec 31, 2018
|
Jan 1, 2019 –
Mar 31, 2019
|
Apr 1, 2019 –
Dec 31, 2019
|
Jul 1, 2017
–
Dec 31,
2017
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
Sold Swaps
|
$53.50
|
$53.73
|
$53.73
|
$53.73
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
2,000
|
3,000
|
3,000
|
3,000
|
-
|
-
|
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
|
Sold Puts
|
$39.62
|
$42.83
|
$42.63
|
$45.00
|
$43.75
|
$2.06
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
17,000
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
Purchased
Puts
|
$50.61
|
$53.04
|
$52.56
|
$56.00
|
$54.69
|
$2.75
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
17,000
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
Sold Calls
|
$60.33
|
$61.99
|
$61.29
|
$70.00
|
$66.18
|
$3.41
|
Volume (bbls/d or
Mcf/d)
|
18,000
|
13,000
|
17,000
|
1,000
|
4,000
|
50,000
|
(1)
|
Based on weighted
average price (before premiums) assuming annual average production
of 85,000 BOE/day, net of royalties and production taxes of
24%.
|
2017 UPDATED GUIDANCE
Enerplus' updated 2017 guidance is summarized below.
|
|
|
Guidance
|
Capital
spending
|
$450
million
|
Average annual
production
|
84,000 – 86,000 BOE/d
(from 81,000 – 85,000 BOE/d)
|
Q4 average
production
|
86,000 – 91,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
39,500 – 41,500
bbls/d (from 38,500 – 41,500 bbls/d)
|
Q4 average crude oil
and natural gas liquids production
|
43,000 – 48,000
bbls/d
|
Average royalty and
production tax rate
|
24%
|
Operating
expense
|
$6.40/BOE (from
$6.85/BOE)
|
Transportation
expense
|
$3.90/BOE (from
$4.00/BOE)
|
Cash G&A
expense
|
$1.75/BOE (from
$1.85/BOE)
|
Differential/Basis
Outlook (1)
|
|
2017 Average U.S.
Bakken crude oil differential (compared to WTI crude
oil):
|
US$(4.50)/bbl
|
2017 Average
Marcellus natural gas sales price differential (compared to NYMEX
natural gas):
|
US$(0.75)/Mcf (from
US$0.60/Mcf)
|
(1)
Excluding transportation
costs.
|
Q2 2017 CONFERENCE CALL DETAILS
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 9:00AM MT (11:00AM
ET) today to discuss these results. Details of the
conference call are as follows:
Date:
|
Friday, August 11,
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=1465072&s=1&k=CADC1AEF83082428A5DE5A9554453FBD
|
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:
|
53114555
|
SELECTED FINANCIAL AND OPERATING RESULTS
|
Three months
ended
June 30,
|
|
Six months
ended
June 30,
|
|
2017
|
2016
|
|
2017
|
2016
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
Adjusted Funds
Flow(4)
|
$
|
114,199
|
$
|
76,047
|
|
$
|
234,119
|
$
|
117,774
|
Dividends to
Shareholders
|
|
7,264
|
|
6,547
|
|
|
14,505
|
|
21,011
|
Net
Income/(Loss)
|
|
129,302
|
|
(168,554)
|
|
|
205,595
|
|
(342,220)
|
Debt Outstanding –
net of Cash
|
|
308,067
|
|
674,147
|
|
|
308,067
|
|
674,147
|
Capital
Spending
|
|
101,739
|
|
48,120
|
|
|
222,086
|
|
91,396
|
Property and Land
Acquisitions
|
|
4,713
|
|
343
|
|
|
7,249
|
|
3,897
|
Property
Divestments
|
|
59,842
|
|
92,735
|
|
|
58,942
|
|
280,503
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.7x
|
|
2.0x
|
|
|
0.7x
|
|
2.0x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
0.53
|
$
|
(0.77)
|
|
$
|
0.85
|
$
|
(1.61)
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
242,127
|
|
218,128
|
|
|
241,710
|
|
212,420
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$
|
35.96
|
$
|
24.96
|
|
$
|
36.14
|
$
|
21.99
|
Royalties and
Production Taxes
|
|
(8.95)
|
|
(5.51)
|
|
|
(8.42)
|
|
(4.72)
|
Commodity Derivative
Instruments
|
|
0.28
|
|
2.53
|
|
|
0.57
|
|
3.51
|
Cash Operating
Expenses
|
|
(5.88)
|
|
(7.20)
|
|
|
(6.23)
|
|
(7.67)
|
Transportation
Costs
|
|
(3.72)
|
|
(2.87)
|
|
|
(3.80)
|
|
(2.88)
|
General and
Administrative Expenses
|
|
(1.53)
|
|
(1.71)
|
|
|
(1.69)
|
|
(1.89)
|
Cash Share-Based
Compensation
|
|
—
|
|
(0.09)
|
|
|
(0.01)
|
|
(0.09)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(1.34)
|
|
(1.21)
|
|
|
(1.31)
|
|
(1.51)
|
Current Income Tax
Recovery/(Expense)
|
|
(0.26)
|
|
0.02
|
|
|
(0.14)
|
|
0.02
|
Adjusted Funds
Flow(4)
|
$
|
14.56
|
$
|
8.92
|
|
$
|
15.11
|
$
|
6.76
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
2017
|
2016
|
|
2017
|
2016
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
36,861
|
|
39,079
|
|
|
35,030
|
|
39,294
|
Natural Gas Liquids
(bbls/day)
|
|
4,133
|
|
4,829
|
|
|
3,648
|
|
5,161
|
Natural Gas
(Mcf/day)
|
|
271,292
|
|
298,503
|
|
|
281,393
|
|
307,827
|
Total
(BOE/day)
|
|
86,209
|
|
93,659
|
|
|
85,577
|
|
95,759
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
48%
|
|
47%
|
|
|
45%
|
|
46%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
$
|
55.66
|
$
|
46.48
|
|
$
|
56.54
|
$
|
39.00
|
Natural Gas Liquids
(per bbl)
|
|
25.14
|
|
15.67
|
|
|
30.57
|
|
13.37
|
Natural Gas (per
Mcf)
|
|
3.48
|
|
1.49
|
|
|
3.56
|
|
1.64
|
(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
|
2017
|
2016
|
|
2017
|
2016
|
WTI crude oil
(US$/bbl)
|
$
|
48.29
|
$
|
45.59
|
|
$
|
50.10
|
$
|
39.52
|
AECO natural gas–
monthly index (CDN$/Mcf)
|
|
2.77
|
|
1.25
|
|
|
2.86
|
|
1.68
|
AECO natural gas –
daily index (CDN$/Mcf)
|
|
2.78
|
|
1.40
|
|
|
2.74
|
|
1.62
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
3.18
|
|
1.95
|
|
|
3.25
|
|
2.02
|
USD/CDN average
exchange rate
|
|
1.34
|
|
1.29
|
|
|
1.33
|
|
1.33
|
Share Trading
Summary
|
CDN
(1) - ERF
|
U.S. (2) - ERF
|
For the three
months ended June 30, 2017
|
(CDN$)
|
(US$)
|
High
|
$
|
11.48
|
$
|
8.54
|
Low
|
$
|
8.97
|
$
|
6.52
|
Close
|
$
|
10.52
|
$
|
8.12
|
(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
|
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. 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
proportion of our anticipated oil and gas production that is hedged
and the effectiveness of such hedges in protecting our 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 programs in 2017 and beyond; expectations
regarding our realized oil and natural gas prices; future royalty
rates on our production and future production taxes; anticipated
cash and non-cash G&A, share-based compensation and financing
expenses; operating and transportation costs; capital spending
levels in 2017 and its impact on our production level and land
holdings; our 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
$2.40/GJ and a USD/CDN exchange rate
of 1.30. 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'
Second Quarter 2017 MD&A.
Electronic copies of Enerplus Corporation's Second 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