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 2018
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
Indicate by check mark whether
the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
Indicate by check mark if
the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)
Indicate by check mark
if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)
Indicate by check mark
whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the securities Exchange Act of 1934.
EXHIBIT
INDEX
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 |
|
|
|
David A. McCoy |
|
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Vice President, General Counsel & Corporate Secretary |
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|
DATE: August 10, 2018
Exhibit 99.1
Enerplus Announces Second Quarter 2018
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 2018 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. 10, 2018 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce second quarter 2018 operating and
financial results. The Company reported second quarter 2018 net income of $12.4 million or $0.05 per share. For the first
six months of 2018, net income was $42.0 million, or $0.17 per share.
HIGHLIGHTS
- Company production of 92,883 BOE per day in the second
quarter
- Company liquids production was up 21% quarter-over-quarter,
averaging 50,050 barrels per day, achieving the high end of second quarter guidance of 48,000 to 50,000 barrels per day
- 33% production growth in North Dakota quarter-over-quarter
- Increasing 2018 annual production guidance to 91,000 to
93,000 BOE per day, from 86,000 to 91,000 BOE per day
- Revising 2018 annual liquids production guidance to the
upper-end of the range, now 49,000 to 50,000 barrels per day, from 46,000 to 50,000 barrels per day
- 2018 capital spending guidance tightened to $585 million
(from $535 to $585 million previously) largely related to increased non-operated activity
- Generated adjusted funds flow of $173.7 million during
the second quarter
- 2018 adjusted funds flow expected to exceed capital expenditures
and dividends by over $100 million based on current forward strip pricing
- Reducing cash G&A guidance by $0.10 per BOE to $1.55
per BOE
- Balance sheet remains among the strongest in the peer group
with a net debt to adjusted funds flow ratio of 0.5 times
"We delivered strong financial and operational
performance through the first half of 2018," said Ian C. Dundas, President and Chief Executive Officer. "Our plans to
continue to drive profitable growth and competitive returns remain firmly on track. We are increasing our production guidance largely
underpinned by high-margin, light oil growth out of the Bakken and we have visibility to generating over $100 million in free cash
flow in the second half of the year. Notwithstanding this strong outlook, we will remain disciplined with our capital allocation
and continue to focus on creating long-term value for our shareholders."
SECOND QUARTER FINANCIAL AND OPERATIONAL
SUMMARY
Production
Production in the second quarter of 2018 averaged 92,883 BOE per day, up 9% from the first quarter. Liquids production for the
quarter averaged 50,050 barrels per day (90% crude oil and 10% natural gas liquids), achieving the high end of second quarter guidance
of 48,000 to 50,000 barrels per day. The Company brought 11 operated high working interest wells on production in North Dakota
during the quarter, which drove the 21% increase in liquids production from the prior quarter.
Natural gas production for the second quarter
averaged 257 MMcf per day, largely flat to the prior quarter.
Enerplus is increasing its 2018 production
guidance to 91,000 to 93,000 BOE per day (from 86,000 to 91,000 BOE per day) and annual liquids production guidance is being revised
to 49,000 to 50,000 barrels per day, the high-end of the previous range of 46,000 to 50,000 barrels per day. The increased production
guidance reflects better than expected well performance in North Dakota along with higher than forecast non-operated production
in the Marcellus.
Net Income and Adjusted Funds Flow
Enerplus generated net income of $12.4 million in the second quarter of 2018, a decrease from the previous quarter primarily as
a result of higher non-cash mark-to-market losses on the Company's commodity derivative instruments resulting from the improvement
in forward crude oil prices.
Adjusted funds flow was $173.7 million during
the second quarter, up 12% compared to $155.2 million in the previous quarter, supported by an increase of 15% in realized crude
oil prices and higher crude oil production during the quarter.
Pricing Realizations and Cost Structure
Bakken crude oil differentials continue to see support from improved egress out of the area due to the Dakota Access Pipeline.
Enerplus' realized Bakken crude oil price differential averaged US$3.42 per barrel below WTI in the second quarter, in-line with
its unchanged 2018 guidance of US$3.50 per barrel below WTI.
The Company's realized Marcellus natural gas
price differential was US$0.69 per Mcf below NYMEX in the second quarter. Although weaker than the first quarter due to seasonality
and pipeline maintenance issues, Marcellus differentials are expected to improve over the remainder of the year as additional pipeline
projects are completed. As a result, the Company's 2018 Marcellus differential guidance of US$0.40 per Mcf below NYMEX is unchanged.
Second quarter operating expenses were $7.20
per BOE, an increase of 3% from the first quarter due to the higher liquids production weighting in the second quarter. Transportation
costs of $3.56 per BOE were largely flat to the prior quarter, and second quarter cash general and administrative ("G&A")
expenses of $1.44 per BOE were 16% lower compared to the prior quarter largely reflective of higher second quarter production.
Enerplus' 2018 guidance for operating costs ($7.00 per BOE) and transportation costs ($3.60 per BOE) remains unchanged. Cash G&A
guidance for 2018 is being reduced to $1.55 per BOE (from $1.65 per BOE).
Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the second quarter was $177.1 million associated with drilling 18.2 net wells and
completing and bringing on production 12.2 net wells across the Company. Enerplus is tightening its 2018 capital spending guidance
to $585 million, from the previous guidance range of $535 to $585 million, as a result of an increase in non-operated activity
and modest inflation on the cost of materials and services. Capital spending for the second half of 2018 is expected to be weighted
to the third quarter.
Total debt net of cash at June 30, 2018 was
$311.8 million. Total debt was comprised of $672.2 million of senior notes outstanding. The Company was undrawn on its $800 million
bank credit facility and had a cash balance of $360.4 million. At June 30, 2018, Enerplus' net debt to adjusted funds flow ratio
was 0.5 times.
AVERAGE DAILY PRODUCTION(1)
|
Three months ended
June 30, 2018 |
|
Six months ended
June 30, 2018 |
|
Crude Oil
(Mbbl/d) |
Natural
Gas
Liquids
(Mbbl/d) |
Natural gas
(MMcf/d) |
Total
Production
(Mboe/d) |
|
Crude Oil
(Mbbl/d) |
Natural Gas
Liquids
(Mbbl/d) |
Natural
gas
(MMcf/d) |
Total
Production
(Mboe/d) |
Williston Basin |
35.8 |
3.7 |
25.3 |
43.7 |
|
31.7 |
3.3 |
22.6 |
38.8 |
Marcellus |
- |
- |
202.4 |
33.7 |
|
- |
- |
205.4 |
34.2 |
Canadian Waterfloods |
9.0 |
0.1 |
3.8 |
9.8 |
|
9.2 |
0.1 |
4.4 |
10.1 |
Other(2) |
0.5 |
0.9 |
25.4 |
5.6 |
|
0.4 |
1.0 |
26.8 |
5.9 |
Total |
45.2 |
4.8 |
257.0 |
92.9 |
|
41.4 |
4.4 |
259.1 |
89.0 |
(1) Table may not add due to rounding.
(2) Six months ended June 30, 2018 includes approximately 600 boe/d of production from Canadian natural gas properties sold in Q1 2018. |
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
|
Three months ended
June 30, 2018 |
|
Six months ended
June 30, 2018 |
|
Operated |
|
Non-Operated |
|
Operated |
|
Non-Operated |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross |
Net |
|
Gross |
Net |
|
Gross |
Net |
|
Gross |
Net |
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin |
11 |
10.3 |
|
2 |
0.7 |
|
19 |
15.5 |
|
2 |
0.7 |
Marcellus |
- |
- |
|
14 |
1.8 |
|
- |
- |
|
25 |
3.3 |
Canadian Waterfloods |
- |
- |
|
- |
- |
|
2 |
1.9 |
|
- |
- |
Other |
- |
- |
|
- |
- |
|
- |
- |
|
1 |
0.3 |
Total |
11 |
10.3 |
|
16 |
2.4 |
|
21 |
17.4 |
|
28 |
4.2 |
(1) Table may not add due to rounding. |
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSET ACTIVITY
Williston Basin
Williston Basin production averaged 43,741 BOE per day (82% oil) during the second quarter of 2018, up 29% from the first quarter
of 2018. Second quarter Williston Basin production was comprised of 40,479 BOE per day in North Dakota, a 33% increase from the
first quarter, and 3,262 BOE per day in Montana.
Enerplus brought on-stream 11 gross operated
wells (94% average working interest) across two pads at Fort Berthold during the second quarter. The six-well Cats pad had an average
completed lateral length of 9,700 feet per well and average peak 30-day production rates per well of 2,013 BOE per day (84% oil,
on a three-stream basis). The five-well Metals North pad had an average completed lateral length of 8,700 feet per well (including
one 4,200 foot lateral) and average peak 30-day production rates per well of 1,684 BOE per day (81% oil, on a three-stream basis).
The Company drilled 13 gross operated wells
(92% average working interest) in the second quarter.
The Company continues to run two operated drilling
rigs and one dedicated completions crew at its Fort Berthold operations.
Marcellus
Marcellus production averaged 202 MMcf per day during the second quarter, a decrease from the previous quarter of 3% primarily
due to pipeline maintenance and seasonally weaker natural gas prices in the second quarter.
Fourteen gross non-operated wells (13% average
working interest) were brought on-stream during the quarter. Thirteen wells had more than 30 days on production as of the date
of this news release with an average completed lateral length of 5,300 feet per well and average peak 30-day production rates per
well of 8.1 MMcf per day.
The Company participated in drilling 16 gross
non-operated wells (13% average working interest) during the second quarter.
Canadian Waterfloods
Canadian waterflood production averaged 9,770 BOE per day (92% oil) during the second quarter, 5% lower than the previous quarter,
primarily due to downtime associated with facility upgrades at Giltedge. Capital activity for the remainder of the year will be
focused on the Company's drilling program at Medicine Hat.
DJ Basin
Enerplus drilled four gross (3.2 net) wells in the DJ Basin during the second quarter. The wells were recently completed and have
commenced flow back. Post-cleanout well results are not expected until later this year.
2018 GUIDANCE
Enerplus' 2018 updated guidance is summarized
below. The Company increased its total production guidance, revised its liquids production and capital guidance, and reduced its
cash G&A expense guidance. All other guidance remains unchanged.
|
Guidance |
Capital spending |
$585 million (from $535 - $585 million) |
Average annual production |
91,000 to 93,000 BOE/day (from 86,000 to 91,000 BOE/day) |
Average annual crude oil and natural gas liquids production |
49,000 to 50,000 bbls/day (from 46,000 to 50,000 bbls/day) |
Average royalty and production tax rate |
25% |
Operating expense |
$7.00/BOE |
Transportation expense |
$3.60/BOE |
Cash G&A expense |
$1.55/BOE (from $1.65/BOE) |
2018 Full-Year Differential/Basis Outlook
(1)
U.S. Bakken crude oil differential (compared to WTI crude oil) |
US$(3.50)/bbl |
Marcellus natural gas sales price differential (compared to NYMEX natural gas) |
US$(0.40)/Mcf |
(1) Excluding transportation costs. |
RISK MANAGEMENT
Enerplus continues to manage price risk through
commodity hedging. Using swaps and collar structures, Enerplus has an average of 22,000 barrels per day of crude oil protected
for the remainder of 2018 (approximately 66% of forecast crude oil production at the midpoint of guidance, net of royalties and
production taxes), 23,140 barrels per day protected in 2019, and 14,000 barrels per day protected in 2020.
For natural gas, Enerplus has 36,685 Mcf per
day protected for the remainder of 2018 (approximately 19% of forecast natural gas production at the midpoint of guidance, net
of royalties and production taxes) using collar structures.
Commodity Hedging Detail (As at August 9,
2018)
|
WTI Crude Oil
(US$/bbl) (1) |
Nymex Natural Gas
(US$/Mcf) (1) |
|
Jul 1, –
Sep 30,
2018 |
Oct 1 –
Dec 31,
2018 |
Jan 1 –
Mar 31,
2019 |
Apr 1 –
Jun 30,
2019 |
Jul 1, –
Sep 30,
2019 |
Oct 1, –
Dec 31,
2019 |
Jan 1, –
Dec 31,
2020 |
Jul 1, –
Oct 31,
2018 |
Nov 1, –
Dec 31,
2018 |
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
Sold Swaps |
$53.73 |
$53.73 |
$53.73 |
- |
- |
- |
- |
- |
- |
Volume (bbls/d or Mcf/d) |
3,000 |
3,000 |
3,000 |
- |
- |
- |
- |
- |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-Way Collars |
|
|
|
|
|
|
|
|
|
Sold Puts |
$42.71 |
$42.74 |
$44.28 |
$44.50 |
$44.64 |
$44.64 |
$46.71 |
- |
- |
Volume (bbls/d or Mcf/d) |
18,000 |
20,000 |
17,000 |
23,500 |
24,500 |
24,500 |
14,000 |
- |
- |
|
|
|
|
|
|
|
|
|
|
Purchased Puts |
$52.53 |
$52.48 |
$54.12 |
$54.59 |
$54.81 |
$54.81 |
$57.14 |
$2.75 |
$2.75 |
Volume (bbls/d or Mcf/d) |
18,000 |
20,000 |
17,000 |
23,500 |
24,500 |
24,500 |
14,000 |
40,000 |
30,000 |
|
|
|
|
|
|
|
|
|
|
Sold Calls |
$61.22 |
$61.10 |
$64.12 |
$65.52 |
$65.95 |
$65.99 |
$72.07 |
$3.38 |
$3.47 |
Volume (bbls/d or Mcf/d) |
18,000 |
20,000 |
17,000 |
23,500 |
24,500 |
24,500 |
14,000 |
40,000 |
30,000 |
(1) Based on weighted average price (before premiums)
(2) The total average deferred premium spent on the three-way collars is US$1.59/bbl from July 1, 2018 to December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
Q2 2018 CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas,
President and CEO will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as
follows:
Date: |
Friday, August 10, 2018 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
587-880-2171 (Alberta) |
|
1-888-390-0546 (Toll Free) |
Conference ID: |
84144621 |
Audiocast: |
https://event.on24.com/wcc/r/1788011/F463A916B7AF3CFED0821F4E99352879 |
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: |
416-764-8677 |
|
1-888-390-0541 (Toll Free) |
Passcode: |
144621 # |
SELECTED FINANCIAL AND OPERATING RESULTS
SELECTED FINANCIAL RESULTS |
Three months ended
June 30, |
|
Six months ended
June 30, |
|
2018 |
2017 |
|
2018 |
2017 |
Financial (000's) |
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
$ |
12,404 |
$ |
129,302 |
|
$ |
42,041 |
$ |
205,595 |
Adjusted Funds Flow(4) |
|
173,708 |
|
114,199 |
|
|
328,870 |
|
234,119 |
Dividends to Shareholders - Declared |
|
7,347 |
|
7,264 |
|
|
14,667 |
|
14,505 |
Debt Outstanding – net of Cash and Restricted Cash |
|
311,782 |
|
308,067 |
|
|
311,782 |
|
308,067 |
Capital Spending |
|
177,082 |
|
101,739 |
|
|
328,554 |
|
222,086 |
Property and Land Acquisitions |
|
2,392 |
|
4,713 |
|
|
14,664 |
|
7,249 |
Property Divestments |
|
(182) |
|
59,842 |
|
|
6,788 |
|
58,942 |
Net Debt to Adjusted Funds Flow Ratio(4) |
|
0.5x |
|
0.7x |
|
|
0.5x |
|
0.7x |
|
|
|
|
|
|
|
|
|
|
Financial per Weighted Average Shares Outstanding |
|
|
|
|
|
|
|
|
|
Net Income - Basic |
$ |
0.05 |
$ |
0.53 |
|
$ |
0.17 |
$ |
0.85 |
Net Income - Diluted |
|
0.05 |
|
0.52 |
|
|
0.17 |
|
0.83 |
Weighted Average Number of Shares Outstanding (000's) |
|
244,862 |
|
242,127 |
|
|
244,369 |
|
241,710 |
|
|
|
|
|
|
|
|
|
|
Selected Financial Results per BOE(1)(2) |
|
|
|
|
|
|
|
|
|
Oil & Natural Gas Sales(3) |
$ |
48.13 |
$ |
35.96 |
|
$ |
45.65 |
$ |
36.14 |
Royalties and Production Taxes |
|
(12.08) |
|
(8.95) |
|
|
(11.28) |
|
(8.42) |
Commodity Derivative Instruments |
|
(2.28) |
|
0.28 |
|
|
(0.57) |
|
0.57 |
Cash Operating Expenses |
|
(7.21) |
|
(5.88) |
|
|
(7.12) |
|
(6.23) |
Transportation Costs |
|
(3.56) |
|
(3.72) |
|
|
(3.54) |
|
(3.80) |
General and Administrative Expenses |
|
(1.44) |
|
(1.53) |
|
|
(1.57) |
|
(1.69) |
Cash Share-Based Compensation |
|
(0.05) |
|
— |
|
|
(0.16) |
|
(0.01) |
Interest, Foreign Exchange and Other Expenses |
|
(0.95) |
|
(1.34) |
|
|
(0.99) |
|
(1.31) |
Current Income Tax Recovery/(Expense) |
|
(0.01) |
|
(0.26) |
|
|
(0.01) |
|
(0.14) |
Adjusted Funds Flow(4) |
$ |
20.55 |
$ |
14.56 |
|
$ |
20.41 |
$ |
15.11 |
|
|
|
|
SELECTED OPERATING RESULTS |
Three months ended
June 30, |
|
Six months ended
June 30, |
|
|
|
2018 |
2017 |
|
2018 |
2017 |
|
|
Average Daily Production(2) |
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls/day) |
|
45,242 |
|
36,861 |
|
|
41,364 |
|
35,030 |
|
|
Natural Gas Liquids (bbls/day) |
|
4,808 |
|
4,133 |
|
|
4,449 |
|
3,648 |
|
|
Natural Gas (Mcf/day) |
|
256,995 |
|
271,292 |
|
|
259,141 |
|
281,393 |
|
|
Total (BOE/day) |
|
92,883 |
|
86,209 |
|
|
89,003 |
|
85,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and Natural Gas Liquids |
|
54% |
|
48% |
|
|
51% |
|
45% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling Price (2)(3) |
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per bbl) |
$ |
79.98 |
$ |
55.66 |
|
$ |
75.34 |
$ |
56.54 |
|
|
Natural Gas Liquids (per bbl) |
|
32.23 |
|
25.14 |
|
|
30.36 |
|
30.57 |
|
|
Natural Gas (per Mcf) |
|
2.68 |
|
3.48 |
|
|
3.09 |
|
3.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Drilled |
|
18 |
|
13 |
|
|
32 |
|
28 |
|
|
(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 |
2018 |
|
2017 |
|
2018 |
|
2017 |
WTI crude oil (US$/bbl) |
$ |
67.88 |
|
$ |
48.29 |
|
$ |
65.37 |
|
$ |
50.10 |
AECO natural gas– monthly index (CDN$/Mcf) |
|
1.02 |
|
|
2.77 |
|
|
1.44 |
|
|
2.86 |
AECO natural gas – daily index (CDN$/Mcf) |
|
1.18 |
|
|
2.78 |
|
|
1.63 |
|
|
2.74 |
NYMEX natural gas – last day (US$/Mcf) |
|
2.80 |
|
|
3.18 |
|
|
2.90 |
|
|
3.25 |
USD/CDN average exchange rate |
|
1.29 |
|
|
1.34 |
|
|
1.28 |
|
|
1.33 |
Share Trading Summary |
CDN(1) - ERF |
|
U.S.(2) - ERF |
For the three months ended June 30, 2018 |
(CDN$) |
|
(US$) |
High |
$ |
17.21 |
|
$ |
13.49 |
Low |
$ |
13.79 |
|
$ |
10.75 |
Close |
$ |
16.58 |
|
$ |
12.60 |
(1) TSX and other Canadian trading data combined. |
(2) NYSE and other U.S. trading data combined. |
|
|
2018 Dividends per Share |
CDN$ |
|
US$(1) |
First Quarter Total |
$ |
0.03 |
|
$ |
0.02 |
Second Quarter Total |
$ |
0.03 |
|
$ |
0.02 |
Total Year to Date |
$ |
0.06 |
|
$ |
0.04 |
(1) CDN$ dividends converted at the relevant foreign exchange rate on the payment date. |
Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this
news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard
of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be
misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method
primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based
on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing
a conversion on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production
volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis
before deduction of royalties. To continue to be comparable with its Canadian peer companies, the summary results contained within
this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes
and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties,
plus Enerplus' royalty interest.
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 2018 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 estimated differentials and our commodity risk management programs
in 2018 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 2018 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 2018 guidance contained in this news release is based on the following forward
prices: WTI US$66.00/bbl, NYMEX US$2.84/Mcf, 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, 2017, and Form 40-F at December 31, 2017).
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", "net debt to adjusted funds flow ratio" and "total debt net of cash" as measures to analyze
operating performance, leverage and liquidity. "Adjusted funds flow" is calculated as 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. "Total debt net of cash" is calculated as senior notes plus any outstanding bank credit facility
balance, minus cash and restricted cash. 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 2018 MD&A.
Electronic copies of Enerplus Corporation's
Second Quarter 2018 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.
SOURCE Enerplus Corporation
View original content: http://www.newswire.ca/en/releases/archive/August2018/10/c5083.html
%CIK: 0001126874
For further information: Ian C. Dundas, President & Chief
Executive Officer, Enerplus Corporation
CO: Enerplus Corporation
CNW 06:00e 10-AUG-18
This regulatory filing also includes additional resources:
ex991.pdf
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