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 2016
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. 14, 2016 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to
announce its results from operations for the third quarter of 2016
and preliminary 2017 outlook.
HIGHLIGHTS:
- Third quarter production averaged 92,077 BOE per day, with
42,598 barrels per day of liquids
- 25% reduction in third quarter operating expenses per BOE
compared to the same period in 2015
- Positive initial results from recent Fort Berthold high density
test, with average production tracking above type curve
expectations
- Preliminary 2017 capital budget of $400
million; approximately 70% allocated to North Dakota with the addition of a second
drilling rig
- Projecting 2017 North Dakota production growth of 25% and total
Company liquids growth of approximately 15% (on a Q4 2016 to Q4
2017 basis)
- Increased 2017 crude oil hedge protection to 17,500 barrels per
day
- Canadian waterflood portfolio optimization with the accretive
acquisition of approximately 3,800 BOE per day (45% liquids) of
high net-back production, with strong secondary recovery growth
potential (closing expected November
2016)
"Enerplus' third quarter results demonstrate our continued
success in reducing the company's cost structure and driving margin
expansion," commented Ian C.
Dundas, President & CEO. "Combined with our top
quartile capital efficiencies and balance sheet strength, Enerplus
is well positioned to reinitiate growth in 2017. Our preliminary
2017 capital budget of $400 million
is largely focused on accelerating liquids production which is
expected to grow approximately 15% on a Q4 2016 to Q4 2017 basis.
Importantly, our capital plans are predicated on profitable and
sustainable growth; we expect our capital spending and dividends to
be approximately balanced with internally generated cash flow at
WTI US$50 per barrel," concluded
Dundas.
THIRD QUARTER FINANCIAL RESULTS SUMMARY
Production averaged 92,077 BOE per day during the quarter,
including 42,598 barrels per day of crude oil and natural gas
liquids. Third quarter production decreased by 2% compared to the
prior quarter as Canadian production was impacted by a previously
announced divestment at the end of second quarter. Production
performance from the Williston
Basin and Marcellus remained strong despite relatively few wells
brought on-stream in the quarter. Williston Basin production was largely flat
from the previous quarter at approximately 33,000 BOE per day,
while Marcellus production increased by 5%, averaging 205 MMcf per
day.
Enerplus is reaffirming its 2016 annual average production
guidance of 93,000 BOE per day (the mid-point of its previous
guidance of 92,000 – 94,000 BOE per day) and is narrowing its
liquids production guidance range to 43,000 – 44,000 barrels per
day (from 43,000 – 45,000 barrels per day) primarily due to weather
related delays to completions activity in North Dakota.
Enerplus continues to forecast sequentially lower fourth quarter
2016 production before reinitiating growth in 2017. Fourth quarter
production is still expected to average approximately 89,000 BOE
per day. Volumes in the fourth quarter are expected to be impacted
by approximately 1,500 BOE per day of curtailed production in the
Marcellus due to low natural gas prices, and price related shut-ins
and minor non-core divestments affecting Canadian gas production by
a combined 1,000 BOE per day. These fourth quarter production
losses are expected to be offset by strong North Dakota production and the Canadian
waterflood acquisition which is projected to close in November 2016.
Enerplus recorded a net loss of $100.7
million ($0.42 per share) in
the third quarter, compared to a net loss of $168.6 million ($0.77 per share) in the previous quarter. The
third quarter net loss was impacted by a non-cash impairment charge
of $61.0 million and a non-cash
valuation allowance on our deferred tax asset as a result of the
decline in the twelve month trailing average commodity prices.
Enerplus generated third quarter funds flow of $80.1 million, up 5% from the previous quarter,
primarily due to higher realized crude oil and natural gas prices
and lower operating expenses, partially offset by lower production
volumes and lower realized commodity hedging gains.
Enerplus' realized oil price for the third quarter averaged
$47.93 per barrel, or US$8.24 per barrel below WTI, compared to
US$9.53 per barrel below WTI in the
previous quarter. The improved price relative to WTI primarily
resulted from a tighter Bakken differential due to declining basin
production and strong local refinery demand. Enerplus' realized
Bakken differential averaged US$6.39
per barrel below WTI in the third quarter, compared to US$8.23 per barrel in the previous quarter.
Natural gas price realizations averaged $2.12 per Mcf, or US$1.19 per Mcf below NYMEX, compared to
US$0.80 per Mcf below NYMEX in the
previous quarter. The weaker natural gas price relative to NYMEX
primarily resulted from a wider Marcellus differential due to high
regional storage inventories combined with seasonal weakness in
demand. Enerplus' realized Marcellus differential averaged
US$1.19 per Mcf below NYMEX in the
third quarter, compared to US$0.76
per Mcf below NYMEX in the previous quarter.
Capital spending for the three and nine months ended
September 30, 2016 was $60.3 million and $151.7
million respectively, with the majority directed to the
Company's crude oil assets. Enerplus is maintaining its full year
2016 capital expenditure guidance of $215
million.
For the fourth consecutive quarter, Enerplus has reduced its
operating expenses. Third quarter operating expenses were
$6.64 per BOE, 6% lower than the
prior quarter and 25% lower compared to the same period in 2015.
Operating expenses for the nine months ended September 30, 2016 were $7.31 per BOE. Enerplus is lowering its full year
2016 guidance for operating expenses to $7.50 per BOE (from $7.90 per BOE) to reflect the performance to date
with an expectation that fourth quarter operating expenses per BOE
will trend higher, due to lower production volumes and a higher
liquids weighting in the production mix.
G&A expenses continued to trend down in the third quarter as
a result of the Company's focus on cost control and the reduction
to staffing levels throughout 2015 and to date in 2016. Third
quarter cash G&A expenses were $1.58 per BOE, 8% lower than the prior quarter
and 29% lower compared to the same period in 2015. Cash G&A
expenses for the nine months ended September
30, 2016 were $1.79 per BOE.
Accordingly, Enerplus is lowering its full year 2016 guidance for
cash G&A expenses to $1.80 per
BOE (from $1.95 per BOE).
Third quarter transportation costs were $3.39 per BOE, an increase of 18% from the prior
quarter primarily due to the addition of a 30,000 MMBtu per day
Marcellus related firm interstate transportation commitment that
came into effect in August 2016,
delivering to higher priced markets.
Enerplus closed the quarter with a strong balance sheet. At
quarter-end, total debt net of cash was $654.1 million comprised of $729.1 million of senior notes outstanding less
$75.0 million in cash.
Enerplus' $800 million bank credit
facility was undrawn. At September 30,
2016, Enerplus' senior debt to adjusted EBITDA ratio was 1.3
times and its debt to funds flow ratio was 2.2 times.
PRODUCTION AND CAPITAL SPENDING(1)
|
|
|
|
|
|
|
Three months
ended
|
|
Nine months
ended
|
|
|
September 30, 2016
|
|
September 30, 2016
|
|
|
Average Production
|
|
Capital Spending
|
|
Average Production
|
|
Capital Spending
|
Crude Oil & NGLs (bbls/day)
|
|
Volumes
|
|
($ millions)
|
|
Volumes
|
|
($ millions)
|
Canada
|
|
13,527
|
|
$
|
8.0
|
|
14,806
|
|
$
|
34.2
|
United
States
|
|
29,071
|
|
$
|
45.1
|
|
29,025
|
|
$
|
97.3
|
Total Crude Oil
& NGLs (bbls/day)
|
|
42,598
|
|
$
|
53.1
|
|
43,831
|
|
$
|
131.5
|
Natural Gas
(Mcf/day)
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
68,604
|
|
$
|
0.1
|
|
82,622
|
|
$
|
0.2
|
United
States
|
|
228,270
|
|
$
|
7.2
|
|
221,527
|
|
$
|
20.1
|
Total Natural Gas
(Mcf/day)
|
|
296,874
|
|
$
|
7.3
|
|
304,149
|
|
$
|
20.3
|
Company Total
(BOE/day)
|
|
92,077
|
|
$
|
60.3
|
|
94,523
|
|
$
|
151.7
|
(1) Table may not add due to
rounding
|
NET DRILLING ACTIVITY(1)– for the three
months ended September 30, 2016
|
|
|
|
|
|
|
Wells
|
|
Wells
|
Crude Oil
|
|
Drilled
|
|
On-stream
|
Canada
|
|
-
|
|
-
|
United
States
|
|
6.6
|
|
2.8
|
Total Crude
Oil
|
|
6.6
|
|
2.8
|
Natural
Gas
|
|
|
|
|
Canada
|
|
-
|
|
-
|
United
States
|
|
-
|
|
0.8
|
Total Natural
Gas
|
|
-
|
|
0.8
|
Company
Total
|
|
6.6
|
|
3.6
|
(1)
Table may not add due to rounding
|
2016 GUIDANCE UPDATE
Updated 2016 guidance is provided below.
Summary of 2016 Expectations
|
|
Revised Guidance
|
|
Previous Guidance
|
Capital
spending
|
|
$215
million
|
|
$215
million
|
Average annual
production
|
|
93,000
BOE/day
|
|
92,000 – 94,000
BOE/day
|
Crude oil and natural
gas liquids volumes
|
|
43,000 – 44,000
barrels/day
|
|
43,000 – 45,000
barrels/day
|
Average royalty and
production tax rate
|
|
22%
|
|
22%
|
Operating
expenses
|
|
$7.50/BOE
|
|
$7.90/BOE
|
Transportation
expense
|
|
$3.15/BOE
|
|
$3.10/BOE
|
Cash G&A
expenses
|
|
$1.80/BOE
|
|
$1.95/BOE
|
WATERFLOOD ACQUISITION
Subsequent to the quarter, and as part of Enerplus' portfolio
optimization activity, the Company entered into an agreement to
acquire an operated (100% working interest), high-netback, light
oil producing asset with significant secondary recovery growth
potential. The asset is located in the Ante Creek area of
Alberta with existing production
of approximately 3,800 BOE per day (45% liquids). The purchase
price is approximately $110 million,
net of anticipated closing adjustments, and will be financed with
existing cash on the balance sheet and the Company's bank credit
facility. Enerplus sees potential to significantly increase crude
oil production from the asset within 24 months with only a modest
capital investment. The transaction is expected to be accretive to
Enerplus on all key metrics including funds flow per debt adjusted
share and production per debt adjusted share. The transaction is
expected to close in November
2016.
Concurrently, and consistent with the portfolio optimization
activities undertaken over the last several years, the Company
continues to explore opportunities to divest additional non-core
properties.
2017 PRELIMINARY OUTLOOK
Enerplus is committed to a financially disciplined, returns
focused strategy which will drive profitable and sustainable growth
for shareholders. With the Company's improving cost structure
driving margin expansion and its strong capital efficiencies,
Enerplus plans to accelerate crude oil growth in 2017 with a
capital program largely focused on North
Dakota. Enerplus has secured a second operated drilling rig
at Fort Berthold commencing operations in January 2017, along with the majority of pressure
pumping services for the program. Enerplus has retained significant
flexibility to reduce activity levels should commodity prices
weaken materially.
Enerplus' preliminary outlook for 2017 capital is $400 million, with approximately 70% targeted for
development in North Dakota. This
level of spending, along with the Company's dividend commitments,
are expected to be largely balanced with internally generated cash
flow in 2017 based on commodity prices of US$50 per barrel WTI and US$3.00 per Mcf NYMEX.
To support its capital program, Enerplus has increased its
average 2017 crude oil hedge position to 17,500 barrels per day.
Additionally, the Company estimates that it has protected
approximately 50% of its 2017 capital costs from escalation through
contracting.
On a fourth quarter 2016 to fourth quarter 2017 basis, Enerplus
expects to grow its North Dakota
production by 25% and total Company liquids production by
approximately 15%. As a result of the higher expected liquids
weighting in the Company's 2017 production mix, Enerplus estimates
its 2017 operating expense will trend towards $8.00 per BOE.
Enerplus expects to provide further details of its 2017 capital
plans in late 2016.
ASSET ACTIVITY
Williston Basin
Williston Basin production
averaged 32,970 BOE per day (88% liquids) during the third quarter
comprised of 28,884 BOE per day in North
Dakota and 4,086 BOE per day in Montana. Capital spending in the Williston Basin was $45.1 million in the third quarter. The Company
continued to operate one drilling rig at Fort Berthold in the third
quarter and drilled six gross-operated wells and brought on-stream
two gross-operated wells. The two operated on-stream wells had an
average initial 30-day production rate of 1,030 BOE per day (84%
crude oil). Current average gross operated well costs (drill,
complete, tie-in and facilities) for a 10,000 foot lateral well
with a high intensity completion are US$8
million.
At the end of the third quarter 2016, Enerplus had approximately
12 net drilled uncompleted wells at Fort Berthold.
Subsequent to the third quarter, Enerplus initiated a three-well
density test targeting tighter well spacing than the Company's
current 1,400 foot interwell spacing pattern. The test wells are
comprised of two Middle Bakken wells spaced at 500 feet offset by
one First Bench Three Forks well at 700 feet. The wells have been
producing for approximately 20 days with average production rates
exceeding type curve expectations. Although this production data is
early-time, it is directionally positive and Enerplus will continue
to monitor the wells' performance to better understand the
implications for higher well density. Enerplus is planning
additional well density tests throughout 2017.
In addition to further well density testing, Enerplus will
continue to optimize its completions design in 2017, testing both
higher and lower proppant volumes around its base design of 1,000
lbs per lateral foot.
Enerplus has secured a second operated drilling rig to commence
operations in January 2017, along
with pressure pumping services for the 2017 program.
Canadian Waterfloods
Third quarter production from the Canadian waterfloods averaged
14,743 BOE per day (83% liquids), an 11% decrease from the second
quarter of 2016 primarily due to a previously announced divestment
which closed in June 2016. Capital
spending in the third quarter was $8.0
million, predominately related to polymer and waterflood
maintenance activities.
Marcellus
Third quarter production from the Marcellus averaged 205 MMcf
per day, a 5% increase from the second quarter of 2016 due to
continued strong well performance. There was limited activity in
the Marcellus in the third quarter with capital spending of
$7.2 million delivering 0.8 net well
completions.
At the end of the third quarter 2016, Enerplus had approximately
5 net drilled uncompleted wells in the Marcellus.
In October 2016, natural gas
pricing weakness in Northeast
Pennsylvania led to production curtailment in the Marcellus.
The low natural gas prices primarily resulted from high regional
storage inventories combined with seasonal weakness in
demand. Enerplus estimates fourth quarter Marcellus
production will be impacted by approximately 1,500 BOE per day due
to curtailment. With the subsequent improvement in gas prices, the
curtailed volumes were brought back online in November 2016.
Risk Management
Enerplus continues to protect a portion of funds flow through
commodity hedging. The Company has increased its crude oil hedge
position in 2017 consistent with its capital spending plans and
waterflood acquisition. Enerplus has also begun to establish
positions in the 2018 and 2019 periods. In addition to being hedged
on over 13,000 barrels per day in the fourth quarter of 2016,
Enerplus has an average of 17,500 barrels per day protected through
swaps and collar structures in 2017.
For natural gas, Enerplus has approximately 58,400 Mcf per day
protected in the fourth quarter of 2016, and 50,000 Mcf per day
protected in 2017 using a combination of swaps and collar
structures.
Commodity Hedging Detail (As at November 1, 2016)
|
|
|
|
WTI Crude
Oil
(US$/bbl)
|
NYMEX Natural
Gas
(US$/Mcf)
|
|
Oct 1, 2016 –
Dec 31, 2016
|
Jan 1, 2017 –
Jun 30, 2017
|
Jul 1, 2017 –
Dec 31, 2017
|
Jan 1, 2018 –
Dec 31, 2018
|
Jan 1, 2019 –
Mar 31, 2019
|
Oct 1, 2016
–
Dec 31,
2016
|
Jan 1, 2017 –
Dec 31, 2017
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
Sold Swaps
|
$
|
52.33
|
$
|
52.50
|
$
|
52.50
|
$
|
53.73
|
$
|
53.73
|
$
|
2.51
|
-
|
Volume (bbls/d or
Mcf/d)
|
1,326
|
2,000
|
2,000
|
3,000
|
3,000
|
33,424
|
-
|
|
|
|
|
|
|
|
|
3 Way Producer
Collars
|
|
|
|
|
|
|
|
Sold Puts
|
$
|
45.09
|
$
|
38.94
|
$
|
39.48
|
$
|
41.00
|
-
|
$
|
2.50
|
$
|
2.06
|
Volume (bbls/d or
Mcf/d)
|
12,000
|
14,000
|
17,000
|
1,000
|
-
|
25,000
|
50,000
|
|
|
|
|
|
|
|
|
Purchased
Puts
|
$
|
57.82
|
$
|
50.29
|
$
|
50.41
|
$
|
54.00
|
-
|
$
|
3.00
|
$
|
2.75
|
Volume (bbls/d or
Mcf/d)
|
12,000
|
14,000
|
17,000
|
1,000
|
-
|
25,000
|
50,000
|
|
|
|
|
|
|
|
|
Sold Calls
|
$
|
71.75
|
$
|
61.14
|
$
|
60.41
|
$
|
62.00
|
-
|
$
|
3.75
|
$
|
3.41
|
Volume (bbls/d or
Mcf/d)
|
12,000
|
14,000
|
17,000
|
1,000
|
-
|
25,000
|
50,000
|
Q3 2016 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:
|
Monday, November 14,
2016
|
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=1285370&s=1&k=2FDBC91307007D1EF8C151424AE3C958
|
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:
|
96185756
|
SELECTED FINANCIAL RESULTS
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
|
|
|
Funds
Flow(4)
|
|
$
|
80,101
|
|
$
|
120,845
|
|
$
|
197,875
|
|
$
|
390,427
|
Dividends to
Shareholders
|
|
|
7,214
|
|
|
30,944
|
|
|
28,225
|
|
|
109,238
|
Net
Income/(Loss)
|
|
|
(100,689)
|
|
|
(292,666)
|
|
|
(442,909)
|
|
|
(898,416)
|
Debt Outstanding -
net of cash
|
|
|
654,071
|
|
|
1,226,552
|
|
|
654,071
|
|
|
1,226,552
|
Capital
Spending
|
|
|
60,277
|
|
|
88,923
|
|
|
151,673
|
|
|
403,912
|
Property and Land
Acquisitions
|
|
|
3,777
|
|
|
2,005
|
|
|
7,674
|
|
|
758
|
Property
Divestments
|
|
|
111
|
|
|
11,865
|
|
|
280,614
|
|
|
203,378
|
Debt to Funds Flow
Ratio(4)
|
|
|
2.2x
|
|
|
2.0x
|
|
|
2.2x
|
|
|
2.0x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
|
$
|
(0.42)
|
|
$
|
(1.42)
|
|
$
|
(2.00)
|
|
$
|
(4.36)
|
Weighted Average
Number of Shares Outstanding(000's)
|
|
|
240,483
|
|
|
206,243
|
|
|
221,843
|
|
|
206,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
|
$
|
27.20
|
|
$
|
27.04
|
|
$
|
23.69
|
|
$
|
28.17
|
Royalties and
Production Taxes
|
|
|
(6.20)
|
|
|
(6.01)
|
|
|
(5.20)
|
|
|
(5.93)
|
Commodity Derivative
Instruments
|
|
|
1.17
|
|
|
5.31
|
|
|
2.75
|
|
|
7.36
|
Cash Operating
Expenses
|
|
|
(6.64)
|
|
|
(8.69)
|
|
|
(7.33)
|
|
|
(8.77)
|
Transportation
Costs
|
|
|
(3.39)
|
|
|
(3.03)
|
|
|
(3.05)
|
|
|
(2.94)
|
General and
Administrative Expenses
|
|
|
(1.58)
|
|
|
(2.24)
|
|
|
(1.79)
|
|
|
(2.21)
|
Cash Share-Based
Compensation
|
|
|
(0.03)
|
|
|
0.35
|
|
|
(0.07)
|
|
|
(0.08)
|
Interest, Foreign
Exchange and Other Expenses
|
|
|
(1.07)
|
|
|
(2.47)
|
|
|
(1.37)
|
|
|
(2.72)
|
Current Income Tax
Recovery
|
|
|
(0.01)
|
|
|
1.59
|
|
|
0.01
|
|
|
0.56
|
Funds
Flow(4)
|
|
$
|
9.45
|
|
$
|
11.85
|
|
$
|
7.64
|
|
$
|
13.44
|
SELECTED OPERATING RESULTS
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
|
37,717
|
|
|
44,888
|
|
|
38,764
|
|
|
41,809
|
Natural Gas
Liquids(bbls/day)
|
|
|
4,881
|
|
|
5,061
|
|
|
5,067
|
|
|
4,652
|
Natural Gas
(Mcf/day)
|
|
|
296,876
|
|
|
365,071
|
|
|
304,150
|
|
|
359,611
|
Total(BOE/day)
|
|
|
92,077
|
|
|
110,794
|
|
|
94,523
|
|
|
106,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil &
Natural Gas Liquids
|
|
|
46%
|
|
|
45%
|
|
|
46%
|
|
|
44%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (per
bbl)
|
|
$
|
47.93
|
|
$
|
48.22
|
|
$
|
41.92
|
|
$
|
50.21
|
Natural Gas
Liquids(per bbl)
|
|
|
13.85
|
|
|
13.51
|
|
|
13.53
|
|
|
18.60
|
Natural Gas (per
Mcf)
|
|
|
2.12
|
|
|
2.08
|
|
|
1.79
|
|
|
2.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells
drilled
|
|
|
7
|
|
|
8
|
|
|
24
|
|
|
44
|
(1)
|
Non-cash
amounts have been excluded.
|
(2)
|
Based on
Company interest production volumes. See "Basis of Presentation"
section in the Third Quarter 2016 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".
|
|
|
Three months ended
September 30,
|
|
Nine months
ended
September 30,
|
Average Benchmark Pricing
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
WTI crude oil
(US$/bbl)
|
|
$
|
44.94
|
|
$
|
46.43
|
|
$
|
41.33
|
|
$
|
51.00
|
AECO natural gas –
monthly index (CDN$/Mcf)
|
|
|
2.20
|
|
|
2.80
|
|
|
1.85
|
|
|
2.80
|
AECO natural gas –
daily index (CDN$/Mcf)
|
|
|
2.32
|
|
|
2.90
|
|
|
1.85
|
|
|
2.77
|
NYMEX natural gas –
last day (US$/Mcf)
|
|
|
2.81
|
|
|
2.77
|
|
|
2.29
|
|
|
2.80
|
USD/CDN exchange
rate
|
|
|
1.31
|
|
|
1.31
|
|
|
1.32
|
|
|
1.26
|
Share Trading Summary
|
|
CDN(1)-ERF
|
|
U.S.(2)-ERF
|
For the three months ended
September 30, 2016
|
|
(CDN$)
|
|
(US$)
|
High
|
|
$
|
10.06
|
|
$
|
7.82
|
Low
|
|
$
|
7.43
|
|
$
|
5.61
|
Close
|
|
$
|
8.42
|
|
$
|
6.41
|
(1)
|
TSX and other
Canadian trading data combined.
|
(2)
|
NYSE and other U.S.
trading data combined.
|
2016
Dividends per Share
|
|
|
|
|
|
|
Payment Month
|
|
CDN$
|
|
US$(1)
|
First Quarter
Total
|
|
$
|
0.09
|
|
$
|
0.06
|
Second Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.03
|
July
|
|
$
|
0.01
|
|
$
|
0.01
|
August
|
|
|
0.01
|
|
|
0.01
|
September
|
|
|
0.01
|
|
|
0.01
|
Third Quarter
Total
|
|
$
|
0.03
|
|
$
|
0.03
|
Total Year to
Date
|
|
$
|
0.15
|
|
$
|
0.12
|
(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 2016 and 2017
average production volumes 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 2016 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 2016 and 2017 and its impact on our production level and
land holdings; our future royalty and production and cash taxes;
our deferred income 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 2016 guidance contained in this news release is based
on the following: a WTI price of US$43.64/bbl, a NYMEX price of US$2.52/Mcf, an AECO price of $2.01/GJ and a USD/CDN exchange rate of 1.32. Our
2017 preliminary outlook contained in this news release is based on
the following: a WTI price of US$50.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.95/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 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 AIF
and Form 40-F at December 31,
2015).
NON-GAAP MEASURES
In this news release, we use the terms "funds flow" and "debt
to funds flow ratio" as measures to analyze operating performance,
leverage and liquidity. "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. "Debt to funds flow ratio" is calculated as total
debt net of cash, divided by a trailing 12 months of funds flow. In
addition, "senior debt to adjusted EBITDA" is used to determine
Enerplus' compliance with financial covenants under its bank credit
facility and outstanding senior notes. Calculation of these terms
is described in Enerplus Corporation's Third Quarter 2016 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 "funds flow" and "debt
to funds flow" are useful supplemental measures as they provide an
indication of the results generated by Enerplus' principal business
activities. However, these measures, and "senior debt to adjusted
EBITDA" 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 2016 MD&A.
Electronic copies of Enerplus Corporation's Third Quarter 2016
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