All financial information contained within this news release has
been prepared in accordance with U.S. GAAP. 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. Readers are also referred to
"Information Regarding Reserves, Resources and Operational
Information", "Notice to U.S. Readers" and "Non-GAAP Measures" at
the end of this news release for information regarding the
presentation of the financial, reserves, contingent resources and
operational information in this news release, as well as the use of
certain financial measures that do not have standard meaning under
U.S. GAAP. A copy of Enerplus' 2017 Financial Statements and
MD&A is available on our website at www.enerplus.com, under our
profile on SEDAR at www.sedar.com and on the EDGAR website at
www.sec.gov. All amounts in this news release are stated in
Canadian dollars unless otherwise specified.
CALGARY, Feb. 23, 2018 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported
fourth quarter 2017 net income of $15.3
million, or $0.06 per share,
and fourth quarter adjusted funds flow of $199.6 million. Full year 2017 net income was
$237.0 million, or $0.98 per share, and full year 2017 adjusted
funds flow was $524.1 million.
HIGHLIGHTS:
- Fourth quarter adjusted funds flow was $199.6 million, which includes $50.1 million related to a portion of the
expected U.S. Alternative Minimum Tax ("AMT") refund. Excluding the
AMT refund, adjusted funds flow was $149.5
million, a 65% increase quarter-over-quarter
- Full year 2017 adjusted funds flow, excluding the AMT refund,
increased by 55% compared to 2016
- Fourth quarter netback before hedging improved by 44% to
$21.45 per BOE compared to the
previous quarter
- Delivered 28% crude oil production growth from the first
quarter to the fourth quarter of 2017
- North Dakota production
increased by 70% from the first quarter to the fourth quarter of
2017
- Balance sheet remains among the strongest in the North American
peer group, ending 2017 with a net debt to adjusted funds flow
ratio of 0.6 times
- Replaced 189% of 2017 production through proved plus probable
("2P") reserves additions, revisions and economic factors at a
finding and development ("F&D") cost of $9.68 per BOE. This included material reserves
growth in North Dakota where the
Company replaced 414% of 2017 production
"In 2017 we accomplished what we set out to do, namely
delivering profitable growth, maintaining our disciplined approach
to capital allocation, and continuing our strong operating
momentum," stated Ian C. Dundas,
President and Chief Executive Officer. "We also continued to have
success in focusing our business through divesting non-strategic
assets which has further improved our cost structure and margin and
reduced liabilities. As evidenced by our strong fourth quarter cash
flow and netback, our company is well positioned to continue to
generate robust cash flow per share growth and create
long-term value for our shareholders."
FOURTH QUARTER & FULL YEAR 2017 SUMMARY
Production
Fourth quarter 2017 production was 88,590
BOE per day, above the Company's fourth quarter guidance range of
86,000 to 88,000 BOE per day, and an increase of 12% from the third
quarter of 2017. The Company's crude oil and natural gas liquids
production averaged 46,822 barrels per day (91% oil) in the fourth
quarter, also above its fourth quarter guidance range of 45,000 to
46,000 barrels per day, and an increase of 20% from the third
quarter of 2017. The production outperformance in the fourth
quarter was primarily driven by higher than forecasted North Dakota and Marcellus volumes, which
together accounted for 76% of fourth quarter production.
Full year 2017 production averaged 84,711 BOE per day, including
40,793 barrels per day of crude oil and natural gas liquids (91%
oil). Full year production was just above the Company's guidance of
84,000 BOE per day of total production and 40,500 barrels per day
of crude oil and natural gas liquids.
Adjusted Funds Flow, Netback and Net Income
The
continued improvement of Enerplus' pricing realizations in the
Bakken and Marcellus, combined with the reductions to the Company's
cost structure, have significantly strengthened the cash flow
generating capability of the business. Fourth quarter 2017 adjusted
funds flow was $199.6 million, which
included $50.1 million related to a
portion of the AMT refund receivable as a result of the enactment
of U.S. tax reform legislation on December
22, 2017. Excluding the impact of the AMT refund, Enerplus'
fourth quarter normalized adjusted funds flow was $149.5 million, 65% higher than the previous
quarter. Full year 2017 adjusted funds flow was $524.1 million, or $474.0
million excluding the impact of the AMT refund, representing
a 55% increase compared to 2016.
Enerplus' netback, before commodity hedging, was $21.45 per BOE in the fourth quarter of 2017.
This represents a 44% increase from the prior quarter and a 47%
increase from the same period in 2016. The significant improvement
in operating netback was driven by improved pricing differentials
in the Bakken and Marcellus, the Company's lower cost structure,
and higher benchmark oil prices.
Fourth quarter net income was $15.3
million and included a $46.2
million non-cash deferred income tax expense from the
remeasurement of the Company's U.S. deferred income tax assets for
the U.S. federal income tax rate reduction from 35% to 21%. This
expense is net of the reversal of the valuation allowance
previously recorded on the Company's AMT credit carryovers. Full
year 2017 net income was $237.0
million.
Pricing Realizations and Cost Structure
Enerplus'
realized Bakken crude oil price differential averaged US$1.61 per barrel below WTI in the fourth
quarter, an improvement from US$3.24
per barrel in the previous quarter. Spot Bakken prices strengthened
considerably throughout 2017 due to the improved egress capacity
from the Bakken. Enerplus' average Bakken crude oil price
differential for the full year 2017 was US$3.72 per barrel below WTI, in-line with the
Company's guidance of US$4.00 per
barrel. The Company expects the strength in Bakken pricing to
continue and is projecting a 2018 realized differential of
US$2.50 per barrel below WTI.
Enerplus' realized Marcellus natural gas sales price
differential narrowed to US$0.81 per
Mcf below NYMEX in the fourth quarter, compared to US$1.02 per Mcf in the previous quarter. Although
Marcellus pricing was weak during October, it strengthened
considerably in November and December in response to seasonal
heating demand and additional industry pipeline capacity coming
into service. Enerplus' average Marcellus natural gas price
differential for the full year 2017 was US$0.76 per Mcf below NYMEX, in-line with the
Company's guidance of US$0.80 per
Mcf. Enerplus believes that the continued build-out of takeaway
capacity is structurally improving pricing dynamics in the
Marcellus region, and with an expected 2.1 Bcf per day of
incremental takeaway projects in 2018 impacting northeast
Pennsylvania, the Company
anticipates the strength in regional pricing will continue.
Enerplus has constructed its Marcellus marketing portfolio with a
view to balancing risk mitigation through firm sales and transport
commitments, with retaining exposure to in-basin pricing. As a
result, Enerplus is positioned to realize the benefit of improving
in-basin pricing with only modest transportation commitments.
Enerplus expects its 2018 realized Marcellus differential will
average US$0.40 per Mcf below NYMEX,
which excludes the Company's Marcellus firm transportation cost of
US$0.18 per Mcf in 2018.
Enerplus continued to drive reductions to its cost structure in
2017 through divesting higher-cost assets and maintaining its focus
on cost control and execution. Fourth quarter 2017 operating,
transportation, and cash general and administrative ("G&A")
expenses per BOE were all lower compared to the prior quarter.
- Operating expenses in the fourth quarter were $6.39 per BOE, 5% lower compared to the prior
quarter. Full year 2017 operating expenses were $6.37 per BOE, 12% lower compared to 2016.
- Transportation costs in the fourth quarter were $3.20 per BOE, 11% lower compared to the prior
quarter. Full year 2017 transportation costs were $3.60 per BOE, 15% higher compared to 2016
primarily due to the increased weighting of U.S. production with
higher associated transport costs.
- Cash G&A expenses in the fourth quarter were $1.55 per BOE, 4% lower compared to the prior
quarter. Full year 2017 cash G&A expenses were $1.63 per BOE, 7% lower compared to 2016.
Capital Expenditures and Balance Sheet
Position
Capital spending was $116.8
million in the fourth quarter of 2017, bringing full year
2017 capital spending to $458.0
million, in-line with the Company's $450 million 2017 budget.
Enerplus further strengthened its financial position during
2017, reducing net debt by 13% year-over-year. Total debt net of
cash at December 31, 2017 was
$325.8 million. Total debt was
comprised of $672.3 million in senior
notes outstanding. The Company was undrawn on its $800 million bank credit facility and had a cash
balance of $346.5 million. At
December 31, 2017, Enerplus' net debt
to adjusted funds flow ratio was 0.6 times.
Divestment Activity and Asset Retirement
Obligation
During the fourth quarter of 2017 and first
quarter of 2018, Enerplus closed a portion of the previously
announced divestments of non-core properties in Alberta. These divestments had associated
production of approximately 1,000 BOE per day. Enerplus continues
to explore options to divest additional Canadian natural gas
assets.
Throughout 2017, Enerplus divested approximately 7,700 BOE per
day (66% natural gas) of production in aggregate from predominantly
lower-margin properties in Canada.
These divestments have helped reduce Enerplus' asset retirement
obligation ("ARO") by 35% year-over-year. The present value of the
Company's ARO was $117.7 million at
December 31, 2017, compared to
$181.7 million at December 31, 2016.
AVERAGE DAILY PRODUCTION(1)
|
Three months
ended
December 31, 2017
|
|
Twelve months
ended
December 31, 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
|
35.8
|
20.1
|
39.2
|
|
28.7
|
19.2
|
31.9
|
Marcellus
|
-
|
193.2
|
32.2
|
|
-
|
198.0
|
33.0
|
Canadian
Waterfloods(2)
|
9.6
|
6.6
|
10.7
|
|
10.9
|
12.2
|
12.9
|
Other(2)
|
1.4
|
30.7
|
6.5
|
|
1.2
|
34.0
|
6.9
|
Total
|
46.8
|
250.6
|
88.6
|
|
40.8
|
263.5
|
84.7
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Includes volumes from
Canadian properties that were divested in 2017.
|
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
|
Three months
ended
December 31, 2017
|
|
Twelve months
ended
December 31, 2017
|
|
Operated
|
|
Non
Operated
|
|
Operated
|
|
Non
Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
7
|
5.2
|
|
6
|
2.1
|
|
36
|
28.5
|
|
8
|
2.5
|
Marcellus
|
-
|
-
|
|
28
|
3.4
|
|
-
|
-
|
|
70
|
7.2
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
6
|
6.0
|
|
-
|
-
|
Other
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
Total
|
7
|
5.2
|
|
34
|
5.4
|
|
43
|
35.5
|
|
78
|
9.7
|
(1)
|
Table may not add due
to rounding.
|
2017 RESERVES SUMMARY
- Replaced 189% of 2017 production, adding 58.0 MMBOE (61% oil)
of 2P reserves from development activities (including revisions and
economic factors).
- Material reserves growth was realized in North Dakota and the Marcellus. The Company
replaced 414% of 2017 North Dakota production, adding 42.2 MMBOE of
2P reserves and 132% of 2017 Marcellus production, adding 95.4 Bcf
of 2P reserves (including revisions and economic factors).
- F&D costs were $13.17 per BOE
for proved developed producing reserves, $11.32 per BOE for proved reserves, and
$9.68 per BOE for 2P reserves,
including future development costs ("FDC").
- Three-year average F&D costs were $9.66 per BOE for proved developed producing
reserves, $9.16 per BOE for proved
reserves, and $7.86 per BOE for 2P
reserves, including FDC.
- Finding, development and acquisition ("FD&A) costs were
$12.48 per BOE for proved reserves
and $10.98 per BOE for 2P reserves,
including FDC. 2017 divestments were generally comprised of
lower-margin Canadian properties. No reserves were acquired in
2017.
- Three-year average FD&A costs were $3.41 per BOE for proved reserves and
$1.05 per BOE for 2P reserves,
including FDC.
- Total 2P reserves, net of divestments, were 397.4 MMBOE at
year-end 2017, representing a 4% increase from year-end 2016.
Excluding divestments, 2P reserves increased by 7% in 2017.
- 2P reserves were comprised of 48% crude oil, 5% natural gas
liquids, and 47% natural gas at year-end 2017.
- Total proved reserves account for 70% of 2P reserves. Proved
developed producing reserves represent 67% of total proved reserves
and 47% of 2P reserves.
- Enerplus' 2P reserves life index increased to 12.6 years at
year-end 2017, from 12.3 years at year-end 2016.
ASSET ACTIVITY
Williston
Basin
Williston Basin
production averaged 39,195 BOE per day (83% oil) during the fourth
quarter of 2017, 27% higher than the third quarter. Fourth quarter
Williston Basin production was
comprised of 35,474 BOE per day in North
Dakota and 3,721 BOE per day in Montana. Enerplus
re-established meaningful growth in North
Dakota during 2017 delivering a 70% production increase over
the course of the year (from the first quarter to the fourth
quarter of 2017).
In the fourth quarter, Enerplus brought on-stream seven gross
operated wells (74% average working interest) across its acreage at
Fort Berthold with an average completed lateral length of 7,540
feet per well and average peak 30-day production rates per well of
1,443 BOE per day (76% oil, on a three-stream basis). This average
rate includes production from two wells that were producing at
restricted rates.
Enerplus continued to see strong outperformance from the four
wells on its Snakes pad that were brought on-stream toward the end
of the third quarter. On average, the Snakes wells have produced
approximately 160,000 barrels of oil per well in 120 days on
production, including the Smooth Green well which has produced over
240,000 barrels of oil in 120 days.
The Company drilled six gross operated wells (77% average
working interest) in the fourth quarter.
Enerplus expects a decline in production from North Dakota in the first quarter of 2018,
relative to the fourth quarter of 2017, followed by sequential
quarterly production growth for the remainder of the year. The
expected decline in the first quarter is due to a completions
schedule that results in on-stream activity weighted to the back
half of the first quarter – in part to mitigate the impact of
severe weather during December and January.
Enerplus expects to spend approximately 75% of its 2018 capital
budget in North Dakota running
two-operated drilling rigs and one dedicated completions crew in
2018. North Dakota production in
2018 is projected to grow by over 30% year-over-year.
Marcellus
Marcellus production averaged 193 MMcf per
day during the fourth quarter, a 2% increase from the previous
quarter. Fourth quarter production was impacted by approximately 35
MMcf per day of price related production curtailments during
October. Enerplus returned to producing at higher rates in November
and December in response to strengthening regional natural gas
prices. Full year 2017 production from the Marcellus averaged 198
MMcf per day.
Twenty-eight gross non-operated wells (12% average working
interest) were brought on-stream during the quarter, of which 22
currently have over 30-days on production. These 22 wells have an
average completed lateral length of 5,800 feet per well and average
peak 30-day production rates per well of 13.1 MMcf per day.
The Company participated in drilling nine gross non-operated
wells (20% average working interest) during the fourth quarter.
Enerplus expects to spend approximately 10% of its 2018 capital
budget in the Marcellus which is projected to keep production
levels broadly flat relative to 2017.
Canadian Waterfloods
Canadian waterflood production
averaged 10,671 BOE per day (88% oil) during the fourth quarter, a
decrease of 8% from the previous quarter primarily due to the
planned shut-in of certain production wells at Ante Creek in
preparation for conversion to water injection wells, and weather
related downtime at Medicine
Hat.
Enerplus expects to spend approximately 10% of its 2018 capital
budget across its Canadian waterflood portfolio.
DJ Basin
Through leasing and farm-in activity,
Enerplus has established a land position of approximately 35,000
net acres in the DJ Basin, located in northwest Weld County, Colorado, for a modest entry
price. Enerplus has drilled and completed one well (Maple
8-67-36-25C) to date. The pilot-hole was drilled to a total
vertical depth of 7,480 feet and a 388 foot section was cored
spanning the entire Niobrara-Codell interval. Core data indicated
significant oil saturations throughout the entire interval.
Subsequent to coring, Enerplus drilled a 9,272 foot horizontal well
in the Codell formation and completed the well using a
high-proppant and high-fluid intensity slick water completion. The
well has produced 46,920 barrels of oil in 156 days on production
and had a peak consecutive 90 day production rate of 434 BOE per
day (78% oil). Due to the high fluid intensity completion and
flowback management, the oil cut and oil rate inclined for most of
the well's initial production period. The well was shut in for
several weeks during the first quarter of 2018 for surface facility
modifications and was only recently brought back on production.
Prior to this the well was producing at a relatively stable rate of
approximately 400 BOE per day (78% oil) after over five months on
production and is tracking cumulative production of 100,000 BOE in
its first 12 months.
The well is producing light oil with a gravity of approximately
39 degrees API which has allowed for oil sales at the lease at a
differential below WTI of US$2.25 per
barrel. Enerplus will continue to monitor the results of the Maple
well and plans to continue delineation activity to test the extent
of commerciality across its acreage position. Enerplus is planning
to drill up to three wells in the DJ Basin in 2018.
2018 GUIDANCE
Enerplus' previously announced and unchanged 2018 guidance is
provided below.
|
|
Capital
spending
|
$535 – 585
million
|
Average annual
production
|
86,000 – 91,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
46,000 – 50,000
bbl/d
|
Average royalty and
production tax rate
|
25%
|
Operating
expense
|
$7.00/BOE
|
Transportation
expense
|
$3.60/BOE
|
Cash G&A
expense
|
$1.65/BOE
|
|
2018
Differential/Basis Outlook(1)
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(2.50)/bbl
|
Marcellus basis
(compared to NYMEX natural gas)
|
US$(0.40)/Mcf
|
(1)
|
Excluding
transportation costs
|
RISK MANAGEMENT UPDATE
Enerplus' commodity hedging positions, as at February 20, 2018, are provided in the tables
below. Based on the mid-point of its 2018 production guidance (net
of royalties), Enerplus has approximately 65% of 2018 crude oil
production protected and 61% of 2019 crude oil production
protected.
|
WTI Crude Oil
(US$/bbl) (1)
|
|
Jan 1, – Jan
31, 2018
|
Feb 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
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
Sold Swaps
|
$55.38
|
$58.32
|
$55.38
|
$53.73
|
$53.73
|
$53.73
|
-
|
Volume
(bbls/d)
|
5,000
|
7,000
|
5,000
|
3,000
|
3,000
|
3,000
|
-
|
|
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
|
|
Sold Puts
|
$42.83
|
$42.83
|
$42.92
|
$42.71
|
$42.74
|
$44.05
|
$44.09
|
Volume
(bbls/d)
|
13,000
|
13,000
|
15,000
|
18,000
|
20,000
|
16,000
|
20,000
|
|
|
|
|
|
|
|
|
Purchased
Puts
|
$53.04
|
$53.04
|
$52.90
|
$52.53
|
$52.48
|
$53.69
|
$53.94
|
Volume
(bbls/d)
|
13,000
|
13,000
|
15,000
|
18,000
|
20,000
|
16,000
|
20,000
|
|
|
|
|
|
|
|
|
Sold Calls
|
$61.99
|
$61.99
|
$61.73
|
$61.22
|
$61.10
|
$63.44
|
$63.84
|
Volume
(bbls/d)
|
13,000
|
13,000
|
15,000
|
18,000
|
20,000
|
16,000
|
20,000
|
(1)
|
Based on weighted
average price (before premiums).
|
|
NYMEX Natural Gas
(US$/Mcf) (1)
|
|
Jan 1 – Mar
31,
2018
|
Apr 1, – Oct
31,
2018
|
Nov 1, – Dec
31,
2018
|
|
|
|
|
Collars
|
|
|
|
Purchased
Puts
|
$2.75
|
$2.75
|
$2.75
|
Volume
(Mcf/d)
|
30,000
|
40,000
|
30,000
|
|
|
|
|
Sold Calls
|
$3.47
|
$3.38
|
$3.47
|
Volume
(Mcf/d)
|
30,000
|
40,000
|
30,000
|
(1) Based on weighted average
price (before premiums).
|
SELECTED FINANCIAL
RESULTS
|
Three months
ended
|
|
|
Twelve months
ended
|
|
December
31,
|
|
|
December
31,
|
|
2017
|
2016
|
|
|
2017
|
2016
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
15,272
|
$
|
840,325
|
|
$
|
236,998
|
$
|
397,416
|
Adjusted Funds
Flow(4)
|
|
199,559
|
|
107,730
|
|
|
524,064
|
|
305,605
|
Dividends to
Shareholders
|
|
7,264
|
|
7,214
|
|
|
29,033
|
|
35,439
|
Debt
Outstanding – net of Cash and Restricted Cash
|
|
325,831
|
|
375,520
|
|
|
325,831
|
|
375,520
|
Capital
Spending
|
|
116,827
|
|
57,462
|
|
|
458,015
|
|
209,135
|
Property and Land
Acquisitions
|
|
3,805
|
|
118,452
|
|
|
13,276
|
|
126,126
|
Property
Divestments
|
|
(1,385)
|
|
389,750
|
|
|
56,196
|
|
670,364
|
Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.6x
|
|
1.2x
|
|
|
0.6x
|
|
1.2x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) -
Basic
|
$
|
0.06
|
$
|
3.49
|
|
$
|
0.98
|
$
|
1.75
|
Net Income/(Loss) -
Diluted
|
|
0.06
|
|
3.43
|
|
|
0.96
|
|
1.72
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
242,129
|
|
240,483
|
|
|
241,929
|
|
226,530
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
Oil &
Natural Gas Sales(3)
|
$
|
41.72
|
$
|
32.81
|
|
$
|
36.93
|
$
|
25.88
|
Royalties and
Production Taxes
|
|
(10.65)
|
|
(7.60)
|
|
|
(8.91)
|
|
(5.77)
|
Commodity Derivative
Instruments
|
|
(0.39)
|
|
1.12
|
|
|
0.28
|
|
2.36
|
Cash Operating
Expenses
|
|
(6.42)
|
|
(7.22)
|
|
|
(6.39)
|
|
(7.31)
|
Transportation
Costs
|
|
(3.20)
|
|
(3.44)
|
|
|
(3.60)
|
|
(3.14)
|
General and
Administrative Expenses
|
|
(1.55)
|
|
(1.63)
|
|
|
(1.63)
|
|
(1.75)
|
Cash Share-Based
Compensation
|
|
(0.01)
|
|
(0.17)
|
|
|
(0.03)
|
|
(0.09)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(1.17)
|
|
(0.97)
|
|
|
(1.24)
|
|
(1.28)
|
Current Tax
Recovery
|
|
6.15
|
|
0.26
|
|
|
1.55
|
|
0.07
|
Adjusted Funds
Flow(4)
|
$
|
24.48
|
$
|
13.16
|
|
$
|
16.96
|
$
|
8.97
|
SELECTED OPERATING
RESULTS
|
Three months
ended
|
|
Twelve months
ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
2016
|
|
2017
|
2016
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
42,374
|
|
37,128
|
|
|
36,935
|
|
38,353
|
Natural Gas Liquids
(bbls/day)
|
|
4,448
|
|
4,413
|
|
|
3,858
|
|
4,903
|
Natural Gas
(Mcf/day)
|
|
250,607
|
|
284,515
|
|
|
263,506
|
|
299,214
|
Total
(BOE/day)
|
|
88,590
|
|
88,960
|
|
|
84,711
|
|
93,125
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
53%
|
|
47%
|
|
|
48%
|
|
46%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
$
|
65.91
|
$
|
53.91
|
|
$
|
58.69
|
$
|
44.84
|
Natural Gas Liquids
(per bbl)
|
|
32.26
|
|
21.31
|
|
|
30.01
|
|
15.29
|
Natural Gas
(per Mcf)
|
|
3.03
|
|
2.89
|
|
|
3.21
|
|
2.06
|
(1)
|
Non‑cash amounts have
been excluded.
|
(2)
|
Based on Company
interest production volumes. See "Basis of Presentation" section in
the Company's management discussion and analysis for the year
ended December 31, 2017 ("2017 MD&A").
|
(3)
|
Before transportation
costs, royalties and commodity derivative instruments.
|
(4)
|
These non‑GAAP
measures may not be directly comparable to similar measures
presented by other entities. See "Non‑GAAP Measures" section in
the 2017 MD&A.
|
|
Three months
ended
|
|
Twelve months
ended
|
|
December
31,
|
|
December
31,
|
Average Benchmark Pricing
|
2017
|
2016
|
|
2017
|
2016
|
WTI crude oil
(US$/bbl)
|
$
|
55.40
|
$
|
49.29
|
|
$
|
50.95
|
$
|
43.32
|
AECO natural
gas – monthly index (CDN$/Mcf)
|
|
1.96
|
|
2.81
|
|
|
2.43
|
|
2.09
|
AECO natural
gas – daily index (CDN$/Mcf)
|
|
1.69
|
|
3.09
|
|
|
2.16
|
|
2.16
|
NYMEX natural
gas – last day (US$/Mcf)
|
|
2.93
|
|
2.98
|
|
|
3.11
|
|
2.46
|
US/CDN average
exchange rate
|
|
1.27
|
|
1.33
|
|
|
1.30
|
|
1.32
|
Share Trading Summary
|
CDN(1) – ERF
|
U.S.(2) – ERF
|
For the twelve
months ended December 31, 2017
|
(CDN$)
|
(US$)
|
High
|
$
|
13.35
|
$
|
10.21
|
Low
|
$
|
8.97
|
$
|
6.52
|
Close
|
$
|
12.31
|
$
|
9.79
|
(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
|
Fourth Quarter
Total
|
$
|
0.03
|
$
|
0.02
|
Total Year to
Date
|
$
|
0.12
|
$
|
0.08
|
(1)
|
CDN$ dividends
converted at the relevant foreign exchange rate on the
payment date.
|
INDEPENDENT RESERVES EVALUATION
All of the Company's reserves, including its U.S. reserves, have
been evaluated in accordance with NI 51-101. Independent reserves
evaluations have been conducted on properties comprising
approximately 92% of the net present value (discounted at 10%,
before tax, using January 1, 2018
forecast prices and costs) of the Company's total 2P reserves.
McDaniel & Associates Consultants Ltd ("McDaniel"), an
independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties
which comprise approximately 59% of the net present value
(discounted at 10%, before tax, using McDaniel's January 1, 2018 forecast prices and costs) of the
Company's 2P reserves located in Canada and all of the Company's reserves
associated with the Company's properties located in North Dakota, Montana and Colorado. The Company has evaluated the
remaining 41% of the net present value of its Canadian properties
using similar evaluation parameters, including the same forecast
price and inflation rate assumptions utilized by McDaniel. McDaniel
has reviewed the Company's internal evaluation of these properties.
Netherland, Sewell & Associates (NSAI), independent petroleum
consultants based in Dallas,
Texas, has evaluated all of the Company's reserves
associated with the Company's properties in Pennsylvania. For consistency in the Company's
reserves reporting, NSAI used McDaniel's January 1, 2018 forecast prices and inflation
rates to prepare its report.
The following information sets out Enerplus' gross and net crude
oil, NGLs and natural gas reserves volumes and the
estimated net present values of future net revenues
associated with such reserves as at December
31, 2017 using forecast price and cost cases, together with
certain information, estimates and assumptions associated with such
reserves estimates. Under different price scenarios, these reserves
could vary as a change in price can affect the economic limit
associated with a property. It should be noted that tables may not
add due to rounding.
Reserves Summary
Reserves
Summary
|
Light &
Medium Oil
(Mbbls)
|
Heavy Oil
(Mbbls)
|
Tight Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Gross
|
|
|
|
|
|
|
|
|
|
Proved
producing
|
8,515
|
19,976
|
48,731
|
77,222
|
8,236
|
54,332
|
552,114
|
186,532
|
|
Proved developed
non-producing
|
21
|
-
|
650
|
671
|
43
|
-
|
4,611
|
1,482
|
|
Proved
undeveloped
|
354
|
2,576
|
41,721
|
44,651
|
4,720
|
1,660
|
246,294
|
90,697
|
|
Total
proved
|
8,890
|
22,552
|
91,101
|
122,543
|
13,000
|
55,992
|
803,018
|
278,712
|
|
Total
probable
|
2,719
|
7,635
|
58,125
|
68,479
|
7,752
|
21,289
|
233,742
|
118,737
|
Proved plus
Probable
|
11,609
|
30,187
|
149,227
|
191,023
|
20,752
|
77,281
|
1,036,760
|
397,448
|
Net
|
|
|
|
|
|
|
|
|
|
Proved
producing
|
7,233
|
16,704
|
39,274
|
63,211
|
6,706
|
52,431
|
444,439
|
152,729
|
|
Proved developed
non-producing
|
21
|
-
|
533
|
554
|
35
|
-
|
3,657
|
1,198
|
|
Proved
undeveloped
|
332
|
2,170
|
33,436
|
35,938
|
3,784
|
1,295
|
195,795
|
72,569
|
|
Total
proved
|
7,586
|
18,873
|
73,242
|
99,701
|
10,525
|
53,726
|
643,891
|
226,496
|
|
Total
probable
|
2,381
|
6,249
|
46,591
|
55,221
|
6,247
|
20,225
|
185,576
|
95,768
|
Proved plus
Probable
|
9,966
|
25,122
|
119,833
|
154,921
|
16,772
|
73,951
|
829,467
|
322,264
|
Reserves Reconciliation
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a gross basis, from
December 31, 2016 to December 31, 2017.
Proved Reserves -
Gross Volumes (Forecast Prices)
|
|
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Proved Reserves
at
Dec. 31, 2016
|
11,621
|
30,232
|
77,566
|
119,419
|
11,825
|
95,769
|
726,614
|
268,307
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(691)
|
(4,730)
|
(134)
|
(5,555)
|
(122)
|
(22,970)
|
(127)
|
(9,527)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
354
|
390
|
19,609
|
20,353
|
2,231
|
28
|
78,672
|
35,701
|
Economic
factors
|
(138)
|
(113)
|
(517)
|
(768)
|
(177)
|
(5,316)
|
(3,296)
|
(2,380)
|
Technical
revisions
|
(541)
|
(1,012)
|
4,084
|
2,531
|
581
|
4,098
|
80,551
|
17,220
|
Production
|
(1,715)
|
(2,215)
|
(9,507)
|
(13,437)
|
(1,338)
|
(15,617)
|
(79,396)
|
(30,610)
|
Proved Reserves
at
Dec. 31, 2017
|
8,890
|
22,552
|
91,101
|
122,543
|
13,000
|
55,992
|
803,018
|
278,712
|
Probable Reserves
- Gross Volumes (Forecast Prices)
|
|
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Probable Reserves
at
Dec. 31, 2016
|
2,645
|
8,721
|
45,432
|
56,798
|
6,273
|
30,521
|
276,169
|
114,186
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(144)
|
(1,101)
|
(36)
|
(1,281)
|
(44)
|
(9,185)
|
(34)
|
(2,861)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
163
|
165
|
15,013
|
15,341
|
1,663
|
12
|
31,211
|
22,208
|
Economic
factors
|
(7)
|
(39)
|
(10)
|
(56)
|
(73)
|
(2,393)
|
21
|
(525)
|
Technical
revisions
|
62
|
(110)
|
(2,274)
|
(2,322)
|
(67)
|
2,335
|
(73,624)
|
(14,271)
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Probable Reserves
at
Dec. 31, 2017
|
2,719
|
7,635
|
58,125
|
68,479
|
7,752
|
21,289
|
233,742
|
118,737
|
Proved Plus
Probable Reserves - Gross Volumes (Forecast Prices)
|
|
|
Light &
Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Tight Oil
(Mbbls)
|
Total Oil
(Mbbls)
|
Natural
Gas
Liquids
(Mbbls)
|
Conventional
Natural Gas
(MMcf)
|
Shale
Gas
(MMcf)
|
Total
(MBOE)
|
Proved Plus
Probable
Reserves at Dec. 31, 2016
|
14,265
|
38,953
|
122,998
|
176,216
|
18,098
|
126,290
|
1,002,783
|
382,493
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(834)
|
(5,831)
|
(170)
|
(6,835)
|
(166)
|
(32,155)
|
(161)
|
(12,388)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
517
|
555
|
34,622
|
35,694
|
3,895
|
40
|
109,882
|
57,909
|
Economic
factors
|
(145)
|
(152)
|
(527)
|
(824)
|
(250)
|
(7,709)
|
(3,275)
|
(2,905)
|
Technical
revisions
|
(479)
|
(1,122)
|
1,810
|
209
|
513
|
6,432
|
6,927
|
2,949
|
Production
|
(1,715)
|
(2,215)
|
(9,507)
|
(13,437)
|
(1,338)
|
(15,617)
|
(79,396)
|
(30,610)
|
Proved Plus
Probable
Reserves at Dec. 31, 2017
|
11,609
|
30,187
|
149,227
|
191,023
|
20,752
|
77,281
|
1,036,760
|
397,448
|
Future Development Costs
Changes in forecast FDC occur annually as a result of
development activities, acquisition and divestment activities and
capital cost estimates that reflect the evaluators' best estimate
of the capital required to bring the proved and proved plus
probable reserves on production. The aggregate of the exploration
and development costs incurred in the most recent year and the
change during the year in estimated future development costs
generally reflect the total finding and development costs related
to reserves additions for that year.
The following is a summary of the independent reserves
evaluators' estimated FDC required to bring the total proved and
proved plus probable reserves on production:
Future Development
Costs
|
Proved
Reserves
|
Proved
Plus
Probable
Reserves
|
($
millions)
|
|
2018
|
474
|
511
|
2019
|
437
|
605
|
2020
|
65
|
469
|
2021
|
32
|
83
|
2022
|
21
|
33
|
Remainder
|
11
|
13
|
Total FDC
Undiscounted
|
1,040
|
1,714
|
Total FDC Discounted
at 10%
|
925
|
1,469
|
F&D and
FD&A Costs – including future development
costs
|
|
|
|
($ millions except
for per BOE amounts)
|
2017
|
2016
|
2015
|
3
Year
|
Proved Plus
Probable Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$458.0
|
$209.1
|
$493.4
|
$1,160.6
|
|
Net change in Future
Development Costs
|
$102.8
|
$(4.0)
|
$(142.2)
|
$(43.4)
|
|
Gross Reserves
additions (MMBOE)
|
58.0
|
42.6
|
41.6
|
142.2
|
|
F&D costs
($/BOE)
|
$9.68
|
$4.82
|
$8.44
|
$7.86
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$415.1
|
$(335.1)
|
$216.2
|
$296.2
|
|
Net change in Future
Development Costs
|
$85.1
|
$(94.5)
|
$(212.5)
|
$(222.0)
|
|
Gross Reserves
additions (MMBOE)
|
45.6
|
10.3
|
14.9
|
70.8
|
|
FD&A costs
($/BOE)
|
$10.98
|
$(41.60)
|
$0.25
|
$1.05
|
|
|
|
|
|
Proved
Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$458.0
|
$209.1
|
$493.4
|
$1,160.6
|
|
Net change in Future
Development Costs
|
$114.0
|
$(124.4)
|
$210.0
|
$199.6
|
|
Gross Reserves
additions (MMBOE)
|
50.5
|
47.2
|
50.7
|
148.5
|
|
F&D costs
($/BOE)
|
$11.32
|
$1.79
|
$13.88
|
$9.16
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$415.1
|
$(335.1)
|
$216.2
|
$296.2
|
|
Net change in Future
Development Costs
|
$96.7
|
$(202.1)
|
$139.7
|
$34.3
|
|
Gross Reserves
additions (MMBOE)
|
41.0
|
24.7
|
31.1
|
96.8
|
|
FD&A costs
($/BOE)
|
$12.48
|
$(21.74)
|
$11.44
|
$3.41
|
|
|
|
|
|
Proved Developed
Producing Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$458.0
|
$209.1
|
$493.4
|
$1,160.6
|
|
Gross Reserves
additions (MMBOE)
|
34.8
|
43.9
|
41.5
|
120.1
|
|
F&D costs
($/BOE)
|
$13.17
|
$4.77
|
$11.90
|
$9.66
|
Forecast Price Assumptions
The forecast price and cost case assumes no legislative or
regulatory amendments, and includes the effects of inflation. The
estimated future net revenue to be derived from the production of
the reserves is based on the following price forecasts supplied by
McDaniel as of January 1, 2018, (and
utilized by NSAI and by the Company in its internal evaluations for
consistency in the Company's reserves reporting), and the following
inflation and exchange rate assumptions.
McDaniel January
2018 Forecast Price Assumptions
|
|
|
WTI
Crude Oil(1)
US$/bbl
|
Light
Crude
Oil(2)
Edmonton
CDN$/bbl
|
Alberta
Heavy Crude Oil(3)
CDN$/bbl
|
U.S. Henry
Hub Gas Price
US$/MMBtu
|
Natural Gas
Alberta Spot
@ AECO
CDN$/MMBtu
|
Exchange
Rate
US$/CDN$
|
Inflation
Rate
%/year
|
|
|
|
|
|
|
|
|
2018
|
58.50
|
70.10
|
45.20
|
3.00
|
2.25
|
0.790
|
0.0
|
2019
|
58.70
|
71.30
|
49.60
|
3.05
|
2.65
|
0.790
|
2.0
|
2020
|
62.40
|
74.90
|
53.60
|
3.25
|
3.05
|
0.800
|
2.0
|
2021
|
69.00
|
80.50
|
57.60
|
3.55
|
3.40
|
0.825
|
2.0
|
2022
|
73.10
|
82.80
|
59.20
|
3.80
|
3.60
|
0.850
|
2.0
|
2023
|
74.50
|
84.40
|
60.30
|
3.85
|
3.65
|
0.850
|
2.0
|
2024
|
76.00
|
86.10
|
61.60
|
3.95
|
3.75
|
0.850
|
2.0
|
2025
|
77.50
|
87.80
|
62.80
|
4.00
|
3.80
|
0.850
|
2.0
|
2026
|
79.10
|
89.60
|
64.10
|
4.10
|
3.90
|
0.850
|
2.0
|
2027
|
80.70
|
91.40
|
65.40
|
4.15
|
3.95
|
0.850
|
2.0
|
2028
|
82.30
|
93.20
|
66.60
|
4.25
|
4.05
|
0.850
|
2.0
|
2029
|
83.90
|
95.00
|
67.90
|
4.35
|
4.15
|
0.850
|
2.0
|
2030
|
85.60
|
97.00
|
69.40
|
4.45
|
4.25
|
0.850
|
2.0
|
2031
|
87.30
|
98.90
|
70.70
|
4.50
|
4.30
|
0.850
|
2.0
|
2032
|
89.10
|
100.90
|
72.10
|
4.60
|
4.35
|
0.850
|
2.0
|
Thereafter
|
(4)
|
(4)
|
(4)
|
(4)
|
(4)
|
0.850
|
(4)
|
(1) West Texas Intermediate
at Cushing, Oklahoma 40 degree API / 0.5% Sulphur.
(2) Edmonton Light Sweet 40
degree API, 0.3% Sulphur.
(3) Heavy Crude Oil 12 degree
API at Hardisty, Alberta (after deducting blending costs to reach
pipeline quality).
(4) Escalation is
approximately 2% per year thereafter.
|
Net Present Value of Future Production Revenue
The following table provides an estimate of the net present
value of Enerplus' future production revenue after deduction of
royalties, estimated future capital and operating expenditures,
before income taxes. It should not be assumed that the present
value of estimated future cash flows shown below is representative
of the fair market value of the reserves.
Net Present Value
of Future Production Revenue – Forecast Prices and Costs
(before tax)
|
Reserves at December
31, 2017, ($ Millions, discounted at)
|
0%
|
5%
|
10%
|
15%
|
Proved developed
producing
|
3,940
|
2,789
|
2,171
|
1,796
|
Proved developed
non-producing
|
16
|
11
|
8
|
6
|
Proved
undeveloped
|
1,527
|
931
|
608
|
411
|
Total
Proved
|
5,483
|
3,731
|
2,788
|
2,213
|
Probable
|
3,397
|
1,699
|
1,023
|
684
|
Total Proved Plus
Probable Reserves (before tax)
|
8,880
|
5,430
|
3,811
|
2,897
|
Contingent Resources
The following table provides a breakdown of the economic,
unrisked best estimate contingent resources associated with a
portion of Enerplus' Fort Berthold, Marcellus, and Canadian
waterflood assets as at December 31,
2017. These contingent resources are economic using
McDaniel's January 1, 2018 forecast
commodity prices, use established technologies and are all
classified in the "development pending" maturity sub-class. There
is uncertainty that it will be commercially viable to produce any
portion of the resources.
The evaluations of contingent resources associated with a
portion of Enerplus' waterflood properties and leases at Fort
Berthold were conducted by Enerplus and audited by McDaniel. NSAI
evaluated 100% of Enerplus' Marcellus shale gas assets in the U.S.,
including the estimate of contingent resources.
Please see Enerplus' Annual Information Form ("AIF") – Appendix
A for additional disclosures related to Enerplus' contingent
resources as at December 31, 2017.
The AIF is available at www.enerplus.com as well as on the
Company's SEDAR profile at www.sedar.com.
Development
Pending Contingent Resources
|
Unrisked "Best
Estimate"
Contingent Resources
|
Contingent
Resources
Net Drilling
Locations
|
Canada
|
|
|
|
Waterfloods – IOR/EOR
on a portion of waterfloods
|
34.1
|
MMBOE
|
51.8
|
Total
Canada
|
34.1
|
MMBOE
|
51.8
|
United States
Properties
|
|
|
|
Fort Berthold –
Bakken/Three Forks Tight Oil wells
|
79.2
|
MMBOE
|
157.9
|
Marcellus - Shale
gas
|
737.6
|
Bcf
|
71.2
|
Total United
States
|
202.1
|
MMBOE
|
229.1
|
Total
Company
|
236.1
|
MMBOE
|
280.9
|
LIVE CONFERENCE CALL
Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today,
February 23, 2018 at 9:00 a.m. MT (11:00 a.m.
ET) to discuss these results. Details of the conference call
are as follows:
Date:
|
Friday, February 23,
2018
|
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=1581105&s=1&k=682A07EC39874D5C3643C2C61153B241
|
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:
|
51750852
|
Electronic copies of Enerplus' 2017 MD&A and Financial
Statements, along with other public information including investor
presentations, are available on the Company's website at
www.enerplus.com.
Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL
INFORMATION
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), "MBOE" (one thousand barrels of oil
equivalent), and "MMBOE" (one million 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. BOE, MBOE and MMBOE 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 and Reserves 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 IFRS and 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 Enerplus' 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.
Unless otherwise specified, all reserves volumes in
this news release (and all information derived therefrom) are based
on "gross reserves" using forecast prices and costs. "Gross
reserves" (as defined in NI 51-101), being Enerplus' working
interest before deduction of any royalties. Enerplus' oil and gas
reserves statement for the year ended December 31, 2017, which will include complete
disclosure of our oil and gas reserves and other oil and gas
information in accordance with NI 51-101, is contained within our
Annual Information Form (AIF) for the year ended December 31, 2017 which is available on our
website at www.enerplus.com and under our SEDAR
profile at www.sedar.com. Additionally, our AIF forms part of our
Form 40-F that is filed with the U.S. Securities and Exchange
Commission and is available on EDGAR at www.sec.gov. Readers are
also urged to review the Management's Discussion & Analysis and
financial statements filed on SEDAR and as part of our Form 40-F on
EDGAR concurrently with this news release for more complete
disclosure on our operations.
Contingent Resources Estimates
This news release contains estimates of "contingent
resources". "Contingent resources" are not, and should not be
confused with, oil and gas reserves. "Contingent resources" are
defined in the Canadian Oil and Gas Evaluation Handbook (the
"COGE Handbook") as "those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology
under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies.
Contingencies may include factors such as ultimate recovery rates,
legal, environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as "contingent
resources" the estimated discovered recoverable quantities
associated with a project in the early evaluation stage. All of
our contingent resources estimates are economic using
established technologies and based on McDaniel's January 1, 2018 forecast prices. Enerplus expects
to develop these contingent resources in the coming years however
it is too early in their development for these resources to be
classified as reserves at this time. There is uncertainty that
Enerplus will produce any portion of the volumes currently
classified as "contingent resources". "Development pending
contingent resources" refer to a "contingent resources" project
maturity sub-class for a particular project where resolution of the
final conditions for development are being actively pursued (there
is a high chance of development) and the project is expected to be
developed in a reasonable timeframe. The "contingent resources"
estimates contained herein are presented as the "best estimate" of
the quantity that will actually be recovered, effective as of
December 31, 2017. A "best
estimate" of contingent resources means that it is equally likely
that the actual remaining quantities recovered will be greater or
less than the best estimate, and if probabilistic methods are used,
there should be at least a 50% probability that the quantities
actually recovered will equal or exceed the best estimate.
For additional information regarding the primary
contingencies which currently prevent the classification of
Enerplus' disclosed "contingent resources" associated with
Enerplus' Marcellus shale gas properties, Enerplus' Fort Berthold
properties, and a portion of Enerplus' Canadian crude oil
properties as reserves and the positive and negative factors
relevant to the "contingent resources" estimates, see Appendix A to
Enerplus' AIF, a copy of which is available under Enerplus' SEDAR
profile at www.sedar.com, and Enerplus' Form
40-F, a copy of which is available under Enerplus' EDGAR profile at
www.sec.gov.
F&D and FD&A Costs
F&D costs presented in this news release are calculated
(i) in the case of F&D costs for proved developed producing
reserves, by dividing the sum of the exploration and development
costs incurred in the year, by the additions to proved developed
producing reserves in the year, (ii) in the case of F&D costs
for proved reserves, by dividing the sum of exploration and
development costs incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves in the year, and (iii) in the case of F&D costs for
proved plus probable reserves, by dividing the sum of exploration
and development costs incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves in the year. The aggregate of the
exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally reflect total finding and development
costs related to its reserves additions for that
year.
FD&A costs presented in this news release are calculated
(i) in the case of FD&A costs for proved reserves, by dividing
the sum of exploration and development costs and the cost of net
acquisitions incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves including net acquisitions in the year, and (ii) in the
case of FD&A costs for proved plus probable reserves, by
dividing the sum of exploration and development costs and the cost
of net acquisitions incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves including net acquisitions in the
year. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally reflect
total finding, development and acquisition costs related to its
reserves additions for that year.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in
this news release has generally been prepared in accordance with
Canadian disclosure standards, which are not comparable in all
respects to United States or other
foreign disclosure standards. Reserves categories such as "proved
reserves" and "probable reserves" may be defined differently under
Canadian requirements than the definitions contained in
the United States Securities and
Exchange Commission (the "SEC") rules. In addition, under
Canadian disclosure requirements and industry practice, reserves
and production are reported using gross (or, as noted above with
respect to production information, "company interest") volumes,
which are volumes prior to deduction of royalty and similar
payments. The practice in the United
States is to report reserves and production using net
volumes, after deduction of applicable royalties and similar
payments. Canadian disclosure requirements require that forecasted
commodity prices be used for reserves evaluations, while the SEC
mandates the use of an average of first day of the month price for
the 12 months prior to the end of the reporting period.
Additionally, the SEC prohibits disclosure of oil and gas resources
in SEC filings, whereas Canadian issuers may disclose oil and gas
resources. Resources are different than, and should not be
construed as reserves. For a description of the definition of, and
the risks and uncertainties surrounding the disclosure of,
contingent resources, see "Contingent Resources Estimates"
above.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking
information and forward-looking statements within the meaning of
applicable securities laws ("forward-looking information"). The use
of any of the words "expect", "anticipate", "continue", "estimate",
"guidance", "believes", "plans", "budget", 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 2018 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 adjusted funds flow; the results from our drilling
program, timing of related production, and ultimate well
recoveries; oil and natural gas prices and differentials and our
commodity risk management programs in 2018 and in the future;
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, net debt to adjusted funds-flow ratio,
financial capacity, liquidity and capital resources to fund capital
spending and working capital requirements; and expectations
regarding our ability to comply with debt covenants under our bank
credit facility and outstanding senior notes.
The forward-looking information contained in this news
release reflects several material factors, expectations and
assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated; that
our development plans will achieve the expected results; that lack
of adequate infrastructure will not result in curtailment of
production and/or reduced realized prices; current commodity price,
differentials 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 our reserve and contingent resource
volumes; the continued availability of adequate debt and/or equity
financing and adjusted funds flow to fund our capital, operating
and working capital requirements, and dividend payments as needed;
the continued availability and sufficiency of our adjusted funds
flow and availability under our bank credit facility to fund our
working capital deficiency; our ability to negotiate debt covenant
relief under our bank credit facility and outstanding senior notes
if required; the availability of third party services; and the
extent of our liabilities. In addition, our 2018 guidance 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, and a USD/CDN exchange
rate of 1.28. We believe 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:
continued low commodity prices environment or further decline of
commodity prices; changes in realized prices of Enerplus' products;
changes in the demand for or supply of our products; unanticipated
operating results, results from our capital spending activities or
production declines; curtailment of our 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 our capital plans or by third party operators of our
properties; increased debt levels or debt service requirements;
inability to comply with debt covenants under our bank credit
facility and outstanding senior notes; inaccurate estimation of our
oil and gas reserve and contingent resource volumes; limited,
unfavourable or a lack of access to capital markets; increased
costs; a lack of adequate insurance coverage; the impact of
competitors, including drilling and completions operations that
offset our operations and that cause Enerplus to reduce or shut-in
individual well production for safety reasons for a period of time;
reliance on industry partners and third party service providers;
and certain other risks detailed from time to time in our public
disclosure documents (including, without limitation, those risks
and contingencies described under "Risk Factors and Risk
Management" in Enerplus' 2017 MD&A and in our other public
filings).
The forward-looking information contained in this press
release speaks only as of the date of this press release, and we do
not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances,
except as may be required pursuant to applicable
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted funds
flow", "net debt to adjusted funds flow", and "netback" 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" is calculated as
total debt net of cash, including restricted cash, divided by
adjusted funds flow.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow",
"net debt to adjusted funds flow", and "netback" 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'
2017 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation