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 November 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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EXHIBIT
INDEX
EXHIBIT 99.1 - |
|
News Release
Dated November 9, 2017 - Enerplus Announces Third 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 |
|
|
|
David A. McCoy |
|
|
|
Vice President, General Counsel & Corporate Secretary |
|
|
|
|
|
DATE: November 9,
2017
Exhibit 99.1
Enerplus Announces Third 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' Third Quarter
2017 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile
at www.sedar.com and on the EDGAR website at www.sec.gov.
CALGARY, Nov. 9, 2017 /CNW/ - Enerplus Corporation ("Enerplus"
or the "Company") (TSX & NYSE: ERF) is pleased to announce its third quarter 2017 operating and financial results.
The Company reported third quarter 2017 net income of $16.1 million, or $0.07 per share. This compares to a third quarter 2016
net loss of $100.7 million, or $0.42 per share.
HIGHLIGHTS
| · | On track to deliver full-year 2017 and fourth quarter
liquids production targets |
| · | 2017 capital spending guidance unchanged at $450 million |
| · | Produced 33,300 BOE per day (85% oil) in October 2017
from North Dakota, up 60% since the first quarter of 2017 |
| · | Ten wells brought on-stream in North Dakota during
the third quarter with average peak 30-day production rates per well of 1,890 BOE per day, including the Smooth Green well with
a peak 30-day production rate of 3,317 BOE per day |
| · | Realized Bakken differential below WTI averaged US$3.24
per barrel in the third quarter; expecting further improvement to US$2.00 per barrel in the fourth quarter |
| · | Generated adjusted funds flow of $90.4 million |
"Our plan for 2017 remains on track and on budget
to drive high-return crude oil production and associated cash flow growth from our top tier North Dakota position," stated
Ian C. Dundas, President and Chief Executive Officer. "Our strategy of allocating capital to deliver sustainable, profitable
cash flow growth continues to enhance our already strong financial position, giving us the flexibility and resiliency to continue
to create long-term value for shareholders."
THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Third quarter 2017 production averaged 79,128 BOE per day,
including 38,926 barrels per day of crude oil and natural gas liquids. Liquids production for the third quarter was 5% lower than
the prior quarter primarily due to the divestment of the Brooks waterflood property which closed in the second quarter, and a completions
program in North Dakota weighted to the end of the quarter (approximately 70% of third quarter net completions occurred in September).
The Company is on track to drive strong fourth quarter oil volumes with North Dakota production in October averaging 33,300
BOE per day (85% oil), compared to 27,210 BOE per day in the third quarter. Total Company liquids production in October averaged
44,600 barrels per day.
Enerplus remains well positioned relative to its full-year
2017 and fourth quarter liquids production targets. The Company has updated its full-year 2017 liquids production guidance to 40,500
barrels per day (from 39,500 to 41,500 barrels per day) and narrowed its fourth quarter liquids production guidance range to 45,000
to 46,000 barrels per day (from 43,000 to 48,000 barrels per day).
Natural gas production for the third quarter averaged 241
MMcf per day, 11% lower than the prior quarter primarily due to the divestment of Canadian shallow gas properties which closed
in the second quarter, and price related production curtailments in the Marcellus during September. Enerplus curtailed approximately
25 MMcf per day of its Marcellus natural gas production during September and approximately 35 MMcf per day in October due to unfavourable
prices in the daily cash market. Since early November, regional pricing has improved and the Company has returned to producing
at an unrestricted rate of approximately 200 MMcf per day in the Marcellus. Although Enerplus anticipates stronger Marcellus
pricing in November and December, the Company remains committed to focusing on value and therefore there may be further curtailment in
the event prices weaken during the remainder of the fourth quarter.
As a result of the Marcellus curtailments in September and
October, Enerplus has revised its total annual average production guidance for 2017 to 84,000 BOE per day (from 84,000 to 86,000
BOE per day) and its fourth quarter production guidance range to 86,000 to 88,000 BOE per day (from 86,000 to 91,000 BOE per day).
This guidance assumes no further Marcellus production curtailments in the fourth quarter. Total Company production in October averaged
82,700 BOE per day.
Enerplus generated adjusted funds flow of $90.4 million in
the third quarter, compared to $114.2 million in the previous quarter. The quarter-over-quarter reduction was primarily due to
wider natural gas differentials and the strengthening of the Canadian dollar in the third quarter. Tighter Bakken differentials
and lower transportation costs in the third quarter partially offset the reduction in adjusted funds flow.
Exploration and development capital spending in the third
quarter was $119.1 million associated with drilling, completing, and bringing 10.3 net wells on production. The Company's 2017
exploration and development capital budget of $450 million is unchanged.
Enerplus' realized Bakken crude oil price differential averaged
US$3.24 per barrel below WTI in the third quarter, an improvement of US$2.19 per barrel relative to the previous quarter. Spot
Bakken prices strengthened considerably throughout the quarter due to the improved egress capacity from the Bakken, on-going Canadian
synthetic supply outages, and incremental demand from refineries for light barrels due to on-going market disruption during an
active hurricane season. Accordingly, Enerplus is narrowing its expected realized Bakken differential to US$2.00 per barrel below
WTI for the fourth quarter and its full-year differential to approximately US$4.00 per barrel below WTI.
Enerplus' realized Marcellus natural gas sales price differential
widened to US$1.02 per Mcf below NYMEX in the third quarter compared to US$0.64 per Mcf below NYMEX in the previous quarter. Enerplus'
transportation and sales contracts and its fixed basis hedges moderated the weakness as the benchmark monthly Transco Leidy price
widened to average US$1.29 per Mcf below NYMEX during the quarter. Marcellus pricing weakened during the quarter due to cooler
than average weather in the northeast United States combined with incremental supply coming on-stream during the quarter in expectation
of flowing on the subsequently delayed Rover Pipeline. Additional Marcellus pipeline capacity is being brought on-line during the
fourth quarter of 2017, including partial capacity of Rover, which is expected to be at full capacity towards the end of the
first quarter of 2018. Although pricing strengthened in early November, Marcellus pricing remained weak in October with Transco
Leidy daily prices averaging US$0.76 per Mcf. Enerplus is widening its full year 2017 Marcellus realized differential guidance
to US$0.80 per Mcf below NYMEX (from US$0.75 per Mcf), and estimates its fourth quarter realized differential will average approximately
US$1.05 per Mcf below NYMEX.
Third quarter operating expenses averaged $6.71 per BOE, 15%
higher compared to the prior quarter. Operating expenses increased in the third quarter primarily due to lower Marcellus production
relative to the previous quarter and higher gas facility charges and well servicing costs on the Company's oil properties.
As a result of the impact of the Marcellus curtailment in September and October, Enerplus is increasing its full-year
2017 operating expenses to $6.50 per BOE, from $6.40 per BOE. This increase to operating expense guidance is more than offset by
reductions in per BOE transportation and cash G&A guidance, noted below.
Transportation costs in the third quarter averaged $3.61 per
BOE, a decrease from $3.72 per BOE in the second quarter of 2017. Transportation costs decreased in the third quarter due to lower
Marcellus production relative to the previous quarter and a stronger Canadian dollar. Enerplus is reducing its 2017 guidance for
transportation costs to $3.70 per BOE, from $3.90 per BOE.
Cash G&A expenses were $1.61 per BOE for the quarter,
compared to $1.53 per BOE in the previous quarter. The modest increase in cash G&A on a BOE basis was due to lower production
volumes relative to the previous quarter. Total cash G&A of approximately $11.7 million was broadly flat to the prior quarter.
Enerplus is reducing its cash G&A expense guidance to $1.70 per BOE from $1.75 per BOE.
Enerplus remains in a strong financial position. Total debt
net of cash at September 30, 2017 was $318.3 million. Total debt was comprised of $667.3 million of senior notes outstanding. The
Company was undrawn on its $800 million bank credit facility, and had a cash balance of $349.0 million. At September 30, 2017,
Enerplus' net debt to adjusted funds flow ratio was 0.7 times.
AVERAGE DAILY PRODUCTION(1)
|
Three months ended September 30,
2017 |
|
Nine months ended September 30,
2017 |
|
Oil & NGL
(Mbbl/d) |
Natural gas
(MMcf/d) |
Total
Production
(Mboe/d) |
|
Oil & NGL
(Mbbl/d) |
Natural gas
(MMcf/d) |
Total
Production
(Mboe/d) |
Williston Basin |
28.0 |
18.7 |
31.0 |
|
26.4 |
19.0 |
29.5 |
Marcellus |
0.0 |
189.7 |
31.6 |
|
0.0 |
199.6 |
33.3 |
Canadian Waterfloods(2) |
10.1 |
8.7 |
11.6 |
|
11.4 |
14.1 |
13.7 |
Other(2) |
0.8 |
24.2 |
4.9 |
|
1.1 |
35.1 |
6.9 |
Total |
38.9 |
241.2 |
79.1 |
|
38.8 |
267.9 |
83.4 |
(1) |
Table may not add due to rounding. |
(2) |
Nine month figures include volumes from Canadian properties that were divested during the first six months of 2017. |
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
|
Three months ended September 30,
2017 |
|
Nine months ended September 30,
2017 |
|
Operated |
|
Non Operated |
|
Operated |
|
Non Operated |
|
Gross |
Net |
|
Gross |
Net |
|
Gross |
Net |
|
Gross |
Net |
Williston Basin |
10 |
8.6 |
|
1 |
0.0 |
|
29 |
23.4 |
|
2 |
0.5 |
Marcellus |
0 |
0.0 |
|
15 |
0.7 |
|
0 |
0.0 |
|
42 |
3.8 |
Canadian Waterfloods |
0 |
0.0 |
|
0 |
0.0 |
|
6 |
6.0 |
|
0 |
0.0 |
Other |
1 |
1.0 |
|
0 |
0.0 |
|
1 |
1.0 |
|
0 |
0.0 |
Total |
11 |
9.6 |
|
16 |
0.7 |
|
36 |
30.4 |
|
44 |
4.3 |
(1) |
Table may not add due to rounding. |
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSET ACTIVITY
Williston Basin
Williston Basin production averaged 30,981 BOE per day (90%
liquids) during the third quarter of 2017, 4% lower than the second quarter. This decrease was expected due to a completions program
in North Dakota weighted to the end of the third quarter, in part a function of pad development. Third quarter Williston Basin
production was comprised of 27,210 BOE per day in North Dakota and 3,771 BOE per day in Montana.
In the third quarter, Enerplus brought on-stream 10 gross
operated wells (86% average working interest) across its acreage at Fort Berthold with an average completed lateral length of 8,770
feet per well and average peak 30-day production rates per well of 1,890 BOE per day (77% oil, on a three-stream basis). Of note
are four-wells on the Snakes pad, located in the northwest of Enerplus' Fort Berthold acreage position, a high productivity area.
The four wells had an average completed lateral length per well of 9,100 feet and average peak 30-day production rates per well
of 2,185 BOE per day (75% oil). The average proppant loading across the 10 operated completions in the quarter was 1,250 pounds
per foot, including two wells, Smooth Green (Snakes pad) and Crane (Cranes pad), testing 2,000 pounds per foot. The Smooth
Green and Crane wells had peak 30-day production rates of 3,317 BOE per day (75% oil) and 1,950 BOE per day (83% oil) respectively.
The Company drilled 10 gross operated wells (66% average working
interest) in the third quarter.
The strong 2017 production growth from North Dakota is set
to continue in the fourth quarter with October production from North Dakota averaging 33,300 BOE per day (85% oil).
Marcellus
Marcellus production averaged 190 MMcf per day during the
third quarter, a reduction of 7% from the previous quarter primarily due to price related curtailments of approximately 25 MMcf
per day during September. Fifteen gross non-operated wells (5% average working interest) were brought on-stream during the quarter
with an average completed lateral length of 6,300 feet per well and average peak 30-day production rates per well of 14.8 MMcf
per day.
The Company participated in drilling 19 gross non-operated
wells (12% average working interest) during the third quarter.
Enerplus continued to curtail approximately 35 MMcf per day
of its Marcellus production in October due to unfavourable prices in the daily cash market. Since early November, regional pricing
has improved and the Company has returned to producing at an unrestricted rate of approximately 200 MMcf per day.
Canadian Waterfloods
Canadian waterflood production averaged 11,588 BOE per day
(87% liquids) during the third quarter, a decrease of 12% from the previous quarter primarily due to the divestment of the Brooks
property during the second quarter. Activity in the quarter was largely focused on waterflood optimization and the continued advancement
of waterflood implementation at Ante Creek, where total water injection has increased to 9,000 barrels of water per day, with a
target injection of approximately 12,000 barrels of water per day by year-end.
2017 UPDATED GUIDANCE
Enerplus' updated 2017 guidance is summarized below.
|
|
|
Guidance |
Capital spending |
$450 million |
Average annual production |
84,000 BOE/d (from 84,000 – 86,000 BOE/d) |
Q4 average production |
86,000 – 88,000 BOE/d (from 86,000 – 91,000 BOE/d) |
Average annual crude oil and natural gas liquids production |
40,500 bbls/d (from 39,500 – 41,500 bbls/d) |
Q4 average crude oil and natural gas liquids production |
45,000 – 46,000 bbls/d (from 43,000 – 48,000 bbls/d) |
Average royalty and production tax rate |
24% |
Operating expense |
$6.50/BOE (from $6.40/BOE) |
Transportation expense |
$3.70/BOE (from $3.90/BOE) |
Cash G&A expense |
$1.70/BOE (from $1.75/BOE) |
2017 Differential/Basis Outlook (1) |
|
Average U.S. Bakken crude oil differential (compared to WTI crude oil): |
US$(4.00)/bbl (from US$(4.50)/bbl) |
Q4 Average U.S. Bakken crude oil differential (compared to WTI crude oil): |
US$(2.00)/bbl |
Average Marcellus natural gas sales price differential (compared to NYMEX natural gas): |
US$(0.80)/Mcf (from US$(0.75)/Mcf) |
Q4 Average Marcellus natural gas sales price differential (compared to NYMEX natural gas): |
US$(1.05)/Mcf |
(1) Excluding transportation costs. |
|
RISK MANAGEMENT
Enerplus continues to manage price risk through commodity
hedging. Using swaps and collar structures, Enerplus has an average of 20,000 barrels per day of crude oil protected for the remainder
of 2017 (approximately 72% of forecast crude oil production at the midpoint of annual average guidance, net of royalties),
approximately 19,500 barrels per day of crude oil protected in 2018, and 10,000 barrels per day of crude oil protected in 2019.
For natural gas, Enerplus has 50,000 Mcf per day protected
for the remainder of 2017 (approximately 25% of forecast natural gas production at the midpoint of annual average guidance, net
of royalties) using collar structures. For 2018, Enerplus has 25,000 Mcf per day protected using collar structures.
Commodity Hedging Detail (As at November 8, 2017) |
|
WTI Crude Oil
(US$/bbl) (1) |
Nymex Natural Gas
(US$/Mcf) (1) |
|
Oct 1, –
Dec 31,
2017 |
Jan 1, –
Mar 31,
2018 |
Apr 1 –
Jun 30,
2018 |
Jul 1 –
Sep 30,
2018 |
Oct 1 –
Dec 31,
2018 |
Jan 1, –
Mar 31,
2019 |
Apr 1, –
Dec 31,
2019 |
Oct 1, 2017 –
Dec 31, 2017 |
Jan 1, 2018 –
Dec 31, 2018 |
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
Sold Swaps |
$53.50 |
$53.73 |
$53.73 |
$53.73 |
$53.73 |
$53.73 |
- |
- |
- |
Volume (bbls/d or Mcf/d) |
2,000 |
3,000 |
3,000 |
3,000 |
3,000 |
3,000 |
- |
- |
- |
|
|
|
|
|
|
|
|
|
|
Three-Way Collars |
|
|
|
|
|
|
|
|
|
Sold Puts |
$39.62 |
$42.83 |
$42.92 |
$42.71 |
$42.74 |
$43.54 |
$43.48 |
$2.06 |
- |
Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
15,000 |
18,000 |
20,000 |
7,000 |
10,000 |
50,000 |
- |
|
|
|
|
|
|
|
|
|
|
Purchased Puts |
$50.61 |
$53.04 |
$52.90 |
$52.53 |
$52.48 |
$53.21 |
$53.53 |
$2.75 |
$2.75 |
Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
15,000 |
18,000 |
20,000 |
7,000 |
10,000 |
50,000 |
25,000 |
|
|
|
|
|
|
|
|
|
|
Sold Calls |
$60.33 |
$61.99 |
$61.73 |
$61.22 |
$61.10 |
$61.14 |
$62.27 |
$3.41 |
$3.46 |
Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
15,000 |
18,000 |
20,000 |
7,000 |
10,000 |
50,000 |
25,000 |
(1) |
Based on weighted average price (before premiums). A portion of the sold puts are settled annually rather than monthly. |
Q3 2017 CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas, President and CEO
will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as follows:
Date: |
Thursday, November 9, 2017 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
647-427-7450 |
|
1-888-231-8191 (toll free) |
Audiocast: |
http://event.on24.com/r.htm?e=1516988&s=1&k=20AE8FC7B0697879EF594B0CE2E9A824 |
To ensure timely participation in the conference call, callers
are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for
30 days following the conference call and can be accessed at the following numbers:
Dial-In: |
416-849-0833 |
|
1-855-859-2056 (toll free) |
Passcode: |
92669366 |
SELECTED FINANCIAL AND OPERATING RESULTS
|
Three months ended
September 30, |
|
Nine months ended
September 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Financial (000's) |
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
$ |
16,131 |
|
$ |
(100,689) |
|
$ |
221,726 |
|
$ |
(442,909) |
Adjusted Funds Flow(4) |
|
90,386 |
|
|
80,101 |
|
|
324,505 |
|
|
197,875 |
Dividends to Shareholders |
|
7,264 |
|
|
7,214 |
|
|
21,769 |
|
|
28,225 |
Debt Outstanding – net of Cash |
|
318,273 |
|
|
654,071 |
|
|
318,273 |
|
|
654,071 |
Capital Spending |
|
119,102 |
|
|
60,277 |
|
|
341,188 |
|
|
151,673 |
Property and Land Acquisitions |
|
2,222 |
|
|
3,777 |
|
|
9,471 |
|
|
7,674 |
Property Divestments |
|
(1,361) |
|
|
111 |
|
|
57,581 |
|
|
280,614 |
Net Debt to Adjusted Funds Flow Ratio(4) |
|
0.7x |
|
|
2.2x |
|
|
0.7x |
|
|
2.2x |
|
|
|
|
|
|
|
|
|
|
|
|
Financial per Weighted Average Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
$ |
0.07 |
|
$ |
(0.42) |
|
$ |
0.92 |
|
$ |
(2.00) |
Weighted Average Number of Shares Outstanding (000's) |
|
242,129 |
|
|
240,483 |
|
|
241,854 |
|
|
221,843 |
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial Results per BOE(1)(2) |
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas Sales(3) |
$ |
33.23 |
|
$ |
27.20 |
|
$ |
35.21 |
|
$ |
23.69 |
Royalties and Production Taxes |
|
(7.98) |
|
|
(6.20) |
|
|
(8.28) |
|
|
(5.20) |
Commodity Derivative Instruments |
|
0.40 |
|
|
1.17 |
|
|
0.51 |
|
|
2.75 |
Cash Operating Expenses |
|
(6.73) |
|
|
(6.64) |
|
|
(6.39) |
|
|
(7.33) |
Transportation Costs |
|
(3.61) |
|
|
(3.39) |
|
|
(3.74) |
|
|
(3.05) |
Cash General and Administrative Expenses |
|
(1.61) |
|
|
(1.58) |
|
|
(1.67) |
|
|
(1.79) |
Cash Share-Based Compensation |
|
(0.10) |
|
|
(0.03) |
|
|
(0.04) |
|
|
(0.07) |
Interest, Foreign Exchange and Other Expenses |
|
(1.17) |
|
|
(1.07) |
|
|
(1.25) |
|
|
(1.37) |
Current Income Tax Recovery/(Expense) |
|
(0.01) |
|
|
(0.01) |
|
|
(0.10) |
|
|
0.01 |
Adjusted Funds Flow(4) |
$ |
12.42 |
|
$ |
9.45 |
|
$ |
14.25 |
|
$ |
7.64 |
|
Three months ended September 30, |
|
Nine months ended September 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Average Daily Production(2) |
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls/day) |
|
35,245 |
|
|
37,717 |
|
|
35,102 |
|
|
38,764 |
Natural Gas Liquids (bbls/day) |
|
3,681 |
|
|
4,881 |
|
|
3,659 |
|
|
5,067 |
Natural Gas (Mcf/day) |
|
241,212 |
|
|
296,876 |
|
|
267,852 |
|
|
304,150 |
Total (BOE/day) |
|
79,128 |
|
|
92,077 |
|
|
83,403 |
|
|
94,523 |
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and Natural Gas Liquids |
|
49% |
|
|
46% |
|
|
46% |
|
|
46% |
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling Price (2)(3) |
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per bbl) |
$ |
54.21 |
|
$ |
47.93 |
|
$ |
55.75 |
|
$ |
41.92 |
Natural Gas Liquids (per bbl) |
|
26.22 |
|
|
13.85 |
|
|
29.09 |
|
|
13.53 |
Natural Gas (per Mcf) |
|
2.58 |
|
|
2.12 |
|
|
3.26 |
|
|
1.79 |
(1) |
Non-cash amounts have been excluded. |
(2) |
Based on Company interest production volumes. See "Presentation of Production Information" below. |
(3) |
Before transportation costs, royalties, and commodity derivative instruments. |
(4) |
These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures" section in this news release. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
Average Benchmark Pricing |
2017 |
2016 |
|
2017 |
2016 |
WTI crude oil (US$/bbl) |
$ |
48.20 |
$ |
44.94 |
|
$ |
49.47 |
$ |
41.33 |
AECO natural gas– monthly index (CDN$/Mcf) |
|
2.04 |
|
2.20 |
|
|
2.58 |
|
1.85 |
AECO natural gas – daily index (CDN$/Mcf) |
|
1.45 |
|
2.32 |
|
|
2.31 |
|
1.85 |
NYMEX natural gas – last day (US$/Mcf) |
|
3.00 |
|
2.81 |
|
|
3.17 |
|
2.29 |
USD/CDN average exchange rate |
|
1.25 |
|
1.31 |
|
|
1.31 |
|
1.32 |
Share Trading Summary |
CDN (1) - ERF |
U.S. (2) - ERF |
For the three months ended September 30, 2017 |
(CDN$) |
(US$) |
High |
$ |
12.58 |
$ |
10.21 |
Low |
$ |
9.75 |
$ |
7.55 |
Close |
$ |
12.31 |
$ |
9.87 |
(1) TSX and other Canadian trading data combined. |
|
|
|
|
(2) NYSE and other U.S. trading data combined. |
|
|
|
|
2017 Dividends per Share |
CDN$ |
|
US$(1) |
First Quarter Total |
$ |
0.03 |
|
$ |
0.02 |
Second Quarter Total |
$ |
0.03 |
|
$ |
0.02 |
Third Quarter Total |
$ |
0.03 |
|
$ |
0.02 |
Total Year to Date |
$ |
0.09 |
|
$ |
0.06 |
(1) |
CDN$ dividends converted at the relevant foreign exchange rate on the payment date. |
|
|
|
|
|
|
|
Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news
release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of
six thousand cubic feet of natural gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading,
particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily
applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the
current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion
on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production
volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis
before deduction of royalties. In order to continue to be comparable with its Canadian peer companies, the summary results contained
within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production
volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other
royalties, plus Enerplus' royalty interest.
Readers are cautioned that the average initial production
rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information
and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the
words "expect", "anticipate", "continue", "estimate", "guidance", "ongoing",
"may", "will", "project", "should", "believe", "plans", "budget",
"strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting
the foregoing, this news release contains forward-looking information pertaining to the following: expected average production
volumes in 2017 and the anticipated production mix; the portion of Marcellus production that is curtailed; the proportion of anticipated
oil and gas production that is hedged and the effectiveness of such hedges in protecting funds flow; the results from the drilling
program and the timing of related production; oil and natural gas prices and differentials and commodity risk management
programs in 2017, 2018, and beyond; expectations regarding realized oil and natural gas prices; future royalty rates on production
and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating
and transportation costs; capital spending levels in 2017 and its impact on production levels and land holdings; future royalty
and production and cash taxes; future debt and working capital levels and debt to funds flow ratios.
The forward-looking information contained in this news
release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus
will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the
expected results; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed
industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus'
reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources
to fund Enerplus' capital and operating requirements, and dividend payments, as needed; availability of third party services; and
the extent of its liabilities. In addition, our updated 2017 guidance contained in this news release is based on the following
prices for the rest of the year: a WTI price of US$50.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.00/GJ and a USD/CDN
exchange rate of 1.28. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking
information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this news release
is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks,
uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking
information including, without limitation: changes, including continued volatility, in commodity prices; changes in realized prices
for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from
Enerplus' capital spending activities or production declines; curtailment of Enerplus' production due to low realized prices or
lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development
plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; Enerplus'
inability to comply with covenants under its bank credit facility and senior notes; changes in estimates of Enerplus' oil and gas
reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate
insurance coverage; the impact of competitors; reliance on industry partners; failure to complete any anticipated acquisitions
or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without
limitation, those risks identified in its Annual Information Form, management's discussion and analysis for the year-ended December
31, 2016, and Form 40-F at December 31, 2016).
The forward-looking information contained in this press
release speak only as of the date of this press release. Enerplus does not undertake any obligation to publicly update or revise
any forward-looking information contained herein, except as required by applicable laws.
NON-GAAP MEASURES
In this news release, we use the terms "adjusted funds
flow" and "net debt to adjusted funds flow ratio" as measures to analyze operating performance, leverage and liquidity.
"Adjusted funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating
working capital and asset retirement obligation expenditures. "Net debt to adjusted funds flow ratio" is calculated as
total debt net of cash and restricted cash, divided by a trailing 12 months of adjusted funds flow. Calculation of these terms
is described in Enerplus' MD&A under the "Liquidity and Capital Resources" section.
Enerplus believes that, in addition to net earnings and
other measures prescribed by U.S. GAAP, the terms "adjusted funds flow" and "net debt to adjusted funds flow"
are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities.
However, these measures are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP.
Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation
of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about
these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Third Quarter 2017 MD&A.
Electronic copies of Enerplus Corporation's Third Quarter
2017 MD&A and Financial Statements, along with other public information including investor presentations, are available on
its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of the Company's audited financial statements
at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
View original content: http://www.newswire.ca/en/releases/archive/November2017/09/c4999.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 09-NOV-17
This regulatory filing also includes additional resources:
ex991.pdf
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