SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Report of Foreign Issuer
pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange
Act of 1934
FOR THE MONTH
OF August 2017
FORM 6-K
COMMISSION FILE NUMBER
1-15150
The Dome Tower
Suite
3000, 333 - 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200
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the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
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EXHIBIT
INDEX
EXHIBIT 99.1 - |
|
News Release
Dated August 11, 2017 - Enerplus Announces Second Quarter 2017 Results |
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
ENERPLUS CORPORATION
BY: |
/s/ |
David A. McCoy |
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|
David A. McCoy |
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Vice President, General Counsel & Corporate Secretary |
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DATE: August 11,
2017
Exhibit 99.1
Enerplus Announces Second Quarter 2017 Results
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. |
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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%. |
|
|
|
|
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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
View original content: http://www.newswire.ca/en/releases/archive/August2017/11/c1725.html
%CIK: 0001126874
For further information: ENERPLUS CORPORATION, The Dome Tower,
Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta, T2P 2Z1, T. 403-298-2200, F. 403-298-2211, www.enerplus.com
CO: Enerplus Corporation
CNW 06:00e 11-AUG-17
This regulatory filing also includes additional resources:
ex991.pdf
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