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' First 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, May 5, 2017 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to
announce its first quarter 2017 operating and financial results.
The Company reported first quarter 2017 net income of $76.3 million, or $0.32 per share. This compares to a first quarter
2016 net loss of $173.7 million, or
$0.84 per share.
HIGHLIGHTS:
- Generated strong adjusted funds flow of $119.9 million
- 24% operating netback improvement quarter-over-quarter
- 18% improvement in realized Bakken differential, 32%
improvement in realized Marcellus differential compared to the
previous quarter
- Operating expenses of $6.59 per
BOE, an 8% reduction quarter-over-quarter
- Completed eight wells at Fort Berthold including three
one-mile (short) lateral wells which had an average peak 30-day
production rate per well of 1,528 BOE per day
- On track to grow total Company liquids production by 25% from
the first quarter of 2017 to the fourth quarter
"The rate of change in our financial metrics has been
significant over the last twelve months," stated Ian C. Dundas, President and Chief Executive
Officer. "We continued to focus our portfolio around high-margin,
high rate-of-return assets, implement meaningful cost
reductions across our business, and strengthen our financial
position, while seeing structural improvements to our realized
pricing in the Bakken and Marcellus. Our first quarter results
demonstrate this step change in the cash flow generating capability
and financial sustainability of our business."
"We are on track with the execution of our 2017 capital program
to deliver strong oil volumes and cash flow growth and are well
positioned to drive sustained, long-term profitable growth," Dundas
added.
FINANCIAL AND OPERATIONAL SUMMARY
First quarter 2017 production averaged 84,937 BOE per day,
including 36,336 barrels per day of crude oil and natural gas
liquids. Total production was approximately 5% lower compared to
the fourth quarter of 2016 due primarily to the divestment of
non-operated North Dakota
production in December 2016.
Subsequent to the quarter-end, Enerplus closed the final portion
of the previously announced divestment of shallow gas assets in
Canada, along with its Brooks
waterflood property. The combined production associated with these
divestments was approximately 7,300 BOE per day, of which 1,700 BOE
per day closed during the first quarter, with the remaining 5,600
BOE per day having closed subsequent to the quarter-end.
Production in the Williston
Basin began building momentum towards the end of the first quarter
as the majority of wells completed during the quarter were brought
on-stream in the latter half. Williston Basin production averaged 25,065 BOE
per day during the quarter, with March production of approximately
27,000 BOE per day. Enerplus is well positioned to drive strong oil
production growth through the year and achieve its fourth quarter
total Company liquids production guidance of 43,000 to 48,000
barrels per day.
Enerplus generated first quarter 2017 adjusted funds flow of
$119.9 million, an 11% increase from
the previous quarter. The strong adjusted funds flow was a result
of Enerplus' continued netback expansion from a combination of
reductions to the Company's cost structure and improving realized
pricing in the Bakken and Marcellus. Enerplus' first quarter 2017
operating netback, before hedging, was $17.99 per BOE, a 24% increase relative to the
fourth quarter of 2016.
Enerplus' commodity hedging program realized cash gains of
$6.6 million in the first quarter of
2017. The Company realized cash losses of $1.0 million on its crude oil contracts and cash
gains of $7.6 million on its natural
gas contracts, including unwinding a portion of its AECO-NYMEX
basis physical contracts in connection with the previously
announced sale of Canadian shallow gas properties.
Pricing dynamics in the Bakken and Marcellus have continued to
improve with the buildout of pipeline infrastructure in both
regions. Enerplus' realized Bakken crude oil price differential
averaged US$5.59 per barrel below WTI
in the first quarter of 2017, an 18% improvement relative to the
previous quarter. Enerplus' realized Marcellus natural gas
sales price differential averaged US$0.60 per Mcf below NYMEX in the first quarter
of 2017, a 32% improvement relative to the previous quarter.
Enerplus has continued to reduce its operating expenses
through savings from divesting higher cost assets and continuing to
optimize its operating processes. First quarter 2017 operating
expenses averaged $6.59 per BOE, 8%
lower compared to the prior quarter. As a result, Enerplus is
lowering its 2017 operating expense guidance to $6.85 per BOE, from $7.25 per BOE. Enerplus expects operating costs
to increase during the second half of 2017 as a result of the
increasing liquids production and scheduled turnarounds in
Canada.
Transportation costs in the first quarter of 2017 averaged
$3.88 per BOE, an increase from
$3.44 per BOE in the fourth quarter
of 2016. The increase in transportation cost per BOE is primarily
due to the divestment of non-operated North Dakota volumes at the end of 2016, and
higher Marcellus production in the first quarter of 2017.
Cash G&A expenses were $1.87
per BOE in the first quarter of 2017, compared to $1.63 per BOE in the previous quarter. The
increase in cash G&A expenses per BOE was largely due to the
lower production volumes in the first quarter of 2017.
Enerplus remains in a strong financial position. Total debt net
of cash and restricted cash at March 31,
2017 was $350.4 million. Total
debt was comprised of $4.0 million
drawn on the Company's $800 million
bank credit facility, and $740.0
million of senior notes outstanding. Enerplus' cash balance
was $393.6 million, including
restricted cash. At March 31, 2017,
Enerplus' net debt to adjusted funds flow ratio was 0.9 times.
Exploration and development capital spending in the first
quarter of 2017 was $120.4 million,
with $85.1 million directed to
North Dakota, $25.1 million directed to the Canadian
waterfloods, and $9.8 million
directed to the Marcellus. Enerplus' 2017 exploration and
development capital budget of $450
million is unchanged.
AVERAGE DAILY PRODUCTION(1)
|
|
First Quarter
2017
|
|
|
Oil &
NGL
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
Production
(Mboe/d)
|
Williston
Basin
|
|
22.0
|
18.3
|
25.1
|
Marcellus
|
|
0.0
|
204.8
|
34.1
|
Canadian
Waterfloods(2)
|
|
13.0
|
20.8
|
16.4
|
Other(2)
|
|
1.3
|
47.8
|
9.3
|
Total
|
|
36.3
|
291.6
|
84.9
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
First quarter
production includes volumes from Canadian properties that were
divested during and subsequent to the quarter-end.
|
SUMMARY OF WELLS BROUGHT ON-STREAM
|
|
|
|
First Quarter
2017
|
|
|
|
|
Operated
|
|
Non
Operated
|
|
|
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
|
|
|
8
|
6.7
|
|
0
|
0.0
|
Marcellus
|
|
|
|
0
|
0.0
|
|
9
|
0.8
|
Canadian
Waterfloods
|
|
|
|
2
|
2.0
|
|
0
|
0.0
|
Total
|
|
|
|
10
|
8.7
|
|
9
|
0.8
|
ASSET ACTIVITY
Williston Basin
Williston Basin production
averaged 25,065 BOE per day (88% liquids) during the first quarter
of 2017, a 22% decrease compared to the fourth quarter of 2016
largely due to the Company's divestment of non-operated
North Dakota production in
December 2016. First quarter
Williston Basin production was
comprised of 20,842 BOE per day in North
Dakota and 4,223 BOE per day in Montana.
During the first quarter of 2017, Enerplus completed and brought
on-stream eight gross operated wells (84% average working interest)
at Fort Berthold. On the Elements pad, Enerplus completed a
two-mile lateral Middle Bakken well that had a peak 30-day
production rate of 1,723 BOE per day. On the Cactus pad, Enerplus
completed four two-mile lateral wells (three Middle Bakken, one
Three Forks) that had extended
cleanout operations impacting initial production rates. The wells
established an average peak 30-day production rate per well of
1,111 BOE per day. Enerplus completed three one-mile lateral wells
(two Middle Bakken, one Three
Forks) that had an average peak 30-day production rate per
well of 1,528 BOE per day.
Enerplus added a second operated drilling rig at Fort Berthold
in January 2017. The Company drilled
seven gross operated wells in the first quarter. Current gross
Enerplus operated drilled and completed well costs for a two-mile
lateral, assuming Enerplus' base completion design of 1,000 pounds
of proppant per lateral foot, are US$6.7
million, with associated facilities costs of US$1.1 million per well.
Bakken price differentials have continued to strengthen over the
past year due to regional production declines, strong regional
demand, and the anticipated start-up of the Dakota Access Pipeline
project in the second quarter of 2017. This project will result in
regional pipeline capacity exceeding current production levels and
is expected to support stronger Bakken prices going forward.
Enerplus' realized Bakken crude oil price differential averaged
US$5.59 per barrel below WTI in the
first quarter of 2017, an 18% improvement relative to the fourth
quarter of 2016. Enerplus continues to expect its Bakken crude oil
differential to average approximately US$4.50 per barrel below WTI during 2017.
Marcellus
Marcellus production averaged 205 MMcf per day during the first
quarter of 2017, a 7% increase compared to the previous quarter.
Improving regional natural gas prices in the Marcellus have led to
an increase in activity levels compared to 2016. Enerplus
participated in nine gross non-operated wells (9% average working
interest) that were brought on-stream during the first quarter of
2017. Six of these wells had more than 30 days on production as of
the date of this news release with an average lateral length of
6,100 feet per well and an average peak 30-day production rate per
well of 18.8 MMcf per day.
The Company participated in drilling 10 gross non-operated wells
(17% average working interest) during the first quarter.
Enerplus' realized Marcellus sales price differential, excluding
transportation and gathering, averaged US$0.60 per Mcf below NYMEX during the first
quarter of 2017. Continued growth in regional natural gas power
plant demand and the steady addition of new pipeline projects in
2016 has resulted in demand exceeding supply in the Northeast U.S.
This has resulted in much stronger regional natural gas prices
relative to prior periods. Enerplus estimates that the Northeast Pennsylvania region currently has
excess egress pipeline capacity, and with additional infrastructure
expected to be brought online over the next few years, Enerplus
expects Marcellus price differentials will continue to remain
strong in 2017 and improve further into 2018. As a result, Enerplus
now expects its Marcellus natural gas realized price differential
to average US$0.60 per Mcf below
NYMEX during 2017.
Canadian Waterfloods
Canadian waterflood production averaged 16,438 BOE per day (79%
liquids) during the first quarter of 2017, an increase of 4% from
the previous quarter largely due to Ante Creek volumes which were
acquired midway through the fourth quarter of 2016. First quarter
volumes include production from the Brooks asset which was divested
subsequent to the quarter-end. Excluding Brooks volumes, Canadian
waterflood production averaged 13,570 BOE per day (80% liquids)
during the first quarter.
Activity at Ante Creek was focused on expanding the supply of
source water for injection, and optimizing facilities in
preparation for increasing water injection. Other activity in the
quarter was focused in Southeast
Saskatchewan and at Cadogan
where the Company drilled nine gross wells including two injector
wells. The drilling programs were completed on time and budget with
initial well results meeting or exceeding type curve
expectations.
RISK MANAGEMENT
Enerplus continues to manage risk through commodity hedging.
Using swaps and collar structures, Enerplus has an average of
18,680 barrels per day of crude oil protected for the remainder of
2017 (approximately 69% of forecast crude oil production net of
royalties), 12,500 barrels per day of crude oil protected in 2018,
and 4,000 barrels per day of crude oil protected in 2019.
For natural gas, Enerplus has 50,000 Mcf per day protected for
the remainder of 2017 (approximately 25% of forecast natural gas
production net of royalties) using collar structures.
Commodity Hedging
Detail (As at May 4, 2017)
|
|
|
|
WTI Crude Oil
(US$/bbl)
|
NYMEX
Natural Gas
(US$/Mcf)
|
|
|
Apr 1, 2017 –
Jun 30, 2017
|
Jul 1, 2017 –
Dec 31, 2017
|
Jan 1, 2018 –
Dec 31, 2018
|
Jan 1, 2019 –
Mar 31, 2019
|
Apr 1, 2019 –
Dec 31, 2019
|
Apr 1, 2017 –
Dec 31, 2017
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
Sold Swaps
|
|
$53.50
|
$53.50
|
$53.73
|
$53.73
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
|
2,000
|
2,000
|
3,000
|
3,000
|
-
|
-
|
|
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
|
|
Sold Puts
|
|
$38.94
|
$39.62
|
$43.13
|
$45.00
|
$43.75
|
$2.06
|
Volume (bbls/d or
Mcf/d)
|
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
|
Purchased
Puts
|
|
$50.29
|
$50.61
|
$54.00
|
$56.00
|
$54.69
|
$2.75
|
Volume (bbls/d or
Mcf/d)
|
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
|
Sold Calls
|
|
$61.14
|
$60.33
|
$63.09
|
$70.00
|
$66.18
|
$3.41
|
Volume (bbls/d or
Mcf/d)
|
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
2017 UPDATED GUIDANCE
Enerplus is reducing its 2017 operating expense guidance to
$6.85 per BOE from $7.25 per BOE and narrowing its expected 2017
average Marcellus natural gas sales price differential to
US$0.60 per Mcf below NYMEX from
US$0.90 per Mcf below NYMEX. All
other guidance is unchanged.
|
|
|
|
|
Guidance
|
Capital
spending
|
|
$450
million
|
Average annual
production
|
|
81,000 – 85,000
BOE/d
|
Q4 average
production
|
|
86,000 – 91,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
|
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
|
|
$6.85 per BOE (from
$7.25)
|
Transportation
expense
|
|
$4.00 per
BOE
|
Cash G&A
expense
|
|
$1.85 per
BOE
|
Differential/Basis
Outlook(1)
|
|
|
2017 Average U.S.
Bakken crude oil differential (compared to WTI crude
oil):
|
|
US$(4.50) per
bbl
|
2017 Average
Marcellus natural gas sales price differential (compared to NYMEX
natural gas):
|
|
US$(0.60) per Mcf
(from US$0.90)
|
(1)
|
Excluding
transportation costs.
|
Q1 2017 CONFERENCE CALL DETAILS
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 8:00AM MT (10:00AM
ET) today to discuss these results. Details of the
conference call are as follows:
Date:
|
|
Friday, May 5,
2017
|
Time:
|
|
8:00 AM MT (10:00 AM
ET)
|
Dial-In:
|
|
647-427-7450
|
|
|
1-888-231-8191 (toll
free)
|
Audiocast:
|
|
http://event.on24.com/r.htm?e=1400951&s=1&k=74DDC295ABF30D38B104D54D466F6D9C
|
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:
|
|
2229316
|
SELECTED FINANCIAL AND OPERATING RESULTS
|
|
Three months ended
March 31,
|
|
|
|
2017
|
|
2016
|
Financial
(000's)
|
|
|
|
|
|
Adjusted Funds
Flow(4)
|
|
$
|
119,920
|
$
|
41,727
|
Dividends to
Shareholders
|
|
|
7,242
|
|
14,464
|
Net
Income/(Loss)
|
|
|
76,293
|
|
(173,666)
|
Debt Outstanding –
net of cash
|
|
|
350,401
|
|
992,837
|
Capital
Spending
|
|
|
120,351
|
|
43,276
|
Property and Land
Acquisitions
|
|
|
2,536
|
|
3,554
|
Property
Divestments
|
|
|
(899)
|
|
187,768
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
|
0.9x
|
|
2.3x
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
0.32
|
$
|
(0.84)
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
|
241,285
|
|
206,716
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
|
$
|
36.33
|
$
|
19.14
|
Royalties and
Production Taxes
|
|
|
(7.89)
|
|
(3.95)
|
Commodity Derivative
Instruments
|
|
|
0.86
|
|
4.45
|
Cash Operating
Expenses
|
|
|
(6.57)
|
|
(8.12)
|
Transportation
Costs
|
|
|
(3.88)
|
|
(2.89)
|
General and
Administrative Expenses
|
|
|
(1.87)
|
|
(2.07)
|
Cash Share-Based
Compensation
|
|
|
(0.02)
|
|
(0.08)
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(1.26)
|
|
(1.81)
|
Current Income Tax
Recovery/(Expense)
|
|
|
(0.01)
|
|
0.02
|
Adjusted Funds
Flow(4)
|
|
$
|
15.69
|
$
|
4.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31,
|
|
|
|
2017
|
|
2016
|
Average Daily
Production(2)
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
33,178
|
|
39,508
|
Natural Gas Liquids
(bbls/day)
|
|
|
3,158
|
|
5,494
|
Natural Gas
(Mcf/day)
|
|
|
291,607
|
|
317,150
|
Total
(BOE/day)
|
|
|
84,937
|
|
97,860
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
|
43%
|
|
46%
|
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
|
Crude Oil (per
bbl)
|
|
$
|
57.53
|
$
|
31.59
|
Natural Gas Liquids
(per bbl)
|
|
|
37.76
|
|
11.34
|
Natural Gas (per
Mcf)
|
|
|
3.63
|
|
1.77
|
(1)
|
Non‑cash amounts have
been excluded.
|
(2)
|
Based on Company
interest production volumes. See "Basis of Presentation" section in
the MD&A.
|
(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
March 31,
|
Average Benchmark
Pricing
|
|
|
|
|
|
2017
|
2016
|
WTI crude oil
(US$/bbl)
|
|
|
|
|
|
$
|
51.92
|
$
|
33.45
|
AECO natural gas–
monthly index (CDN$/Mcf)
|
|
|
|
|
|
|
2.94
|
|
2.11
|
AECO natural gas –
daily index (CDN$/Mcf)
|
|
|
|
|
|
|
2.69
|
|
1.83
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
|
|
|
|
|
3.32
|
|
2.09
|
USD/CDN average
exchange rate
|
|
|
|
|
|
|
1.32
|
|
1.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share Trading
Summary
|
|
|
|
|
|
CDN(1) - ERF
|
U.S. (2) - ERF
|
For the three
months ended March 31, 2017
|
|
|
|
|
|
(CDN$)
|
(US$)
|
High
|
|
|
|
|
|
$
|
13.35
|
$
|
9.95
|
Low
|
|
|
|
|
|
$
|
9.72
|
$
|
7.26
|
Close
|
|
|
|
|
|
$
|
10.71
|
$
|
8.05
|
(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
|
(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 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 2017 guidance contained in this news release is based
on the following: a WTI price of US$55.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.75/GJ and a USD/CDN exchange rate of
1.35. 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 future decline, 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 and Form 40-F at December 31, 2016).
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'
First Quarter 2017 MD&A.
Electronic copies of Enerplus Corporation's First 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 our 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