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' 2018 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. 22, 2019 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today
reported fourth quarter 2018 cash flow from operating
activities of $221.6 million and
fourth quarter 2018 net income of $249.3
million, or $1.03 per
share.
ANNUAL HIGHLIGHTS:
- 22% liquids production growth year-over-year
- 44% increase in adjusted funds flow year-over-year
- Generated free cash flow of $160
million in 2018
- Returned $108 million to
shareholders in 2018 through share repurchases and dividends
- Ended 2018 with a net debt to adjusted funds flow ratio of 0.4
times
- Replaced 194% of 2018 production through proved plus probable
("2P") reserves additions, revisions and economic factors at a
finding and development ("F&D") cost of $13.74 per BOE. This included material reserves
growth in North Dakota where the
Company replaced 244% of 2018 production
- Total 2P reserves increased 8% year-over-year, with 2P oil
reserves increasing 9%
"We delivered strong results in 2018 having achieved the
high-end of our production guidance range, along with generating
meaningful free cash flow and returning over $100 million to shareholders," stated
Ian C. Dundas, President and Chief
Executive Officer. "With our best in class balance sheet,
competitive oil growth outlook and visibility to free cash flow
based on prevailing commodity prices, we remain well positioned to
create value for our shareholders in 2019."
FOURTH QUARTER & FULL YEAR 2018 SUMMARY
Production
Fourth quarter 2018 production was at the
high-end of the Company's guidance range and modestly higher than
the prior quarter. Total fourth quarter production averaged 97,860
BOE per day, including oil and natural gas liquids production of
54,451 barrels per day (92% oil).
Full year 2018 production was also at the high-end of the
Company's guidance range, averaging 93,216 BOE per day, including
49,910 barrels per day of crude oil and natural gas liquids (91%
oil). Year-over-year, the Company's 2018 production increased by
10%, with liquids production increasing by 22%. This growth was
largely driven by North Dakota
production, which increased by 42%.
Cash Flow From Operating Activities and Adjusted Funds
Flow
Fourth quarter cash flow from operating activities
increased to $221.6 million from
$216.1 million in the third quarter.
Full year 2018 cash flow from operating activities was $738.8 million, 55% higher than 2017.
Fourth quarter adjusted funds flow increased to $214.3 million from $210.4
million in the third quarter. Fourth quarter adjusted funds
flow benefited from a $27.2 million
Alternative Minimum Tax ("AMT") refund expected to be realized in
2019. Enerplus expects to realize the remaining $27.2 million in AMT refund in 2020 and 2021.
Full year 2018 adjusted funds flow was $753.5 million, 44% higher than 2017.
Higher realized commodity prices and increased production
volumes resulted in significant increases to cash flow from
operating activities and adjusted funds flow for 2018 compared to
2017.
Net Income and Adjusted Net Income
Fourth quarter net
income was $249.3 million
($1.03 per share) compared to
$86.9 million ($0.35 per share) in the prior quarter. Full year
2018 net income was $378.3 million
($1.55 per share) compared to
$237.0 million ($0.98 per share) in 2017.
Fourth quarter adjusted net income was $102.2 million ($0.42 per share) compared to $97.3 million ($0.40 per share) in the prior quarter. Full year
2018 adjusted net income was $344.8
million ($1.41 per share)
compared to $132.2 million
($0.55 per share) in 2017. Adjusted
net income is calculated as net income adjusted for unrealized
derivative instrument gain/loss, asset impairment, gain on
divestment of assets, unrealized foreign exchange gain/loss, and
the tax effect of these items. The calculation of adjusted net
income is provided in the "Non-GAAP Measures" section in the 2018
MD&A.
Pricing Realizations and Cost Structure
Enerplus'
realized Bakken crude oil price differential widened to
US$5.60 per barrel below WTI in the
fourth quarter, from US$2.54 per
barrel in the previous quarter. The weaker fourth quarter pricing
was due to significant seasonal refinery maintenance which
temporarily reduced demand for Bakken oil. Enerplus' Bakken crude
oil price differential for the full year 2018 averaged US$3.78 per barrel below WTI, approximately flat
year-over-year.
Enerplus' realized Marcellus natural gas sales price
differential improved to US$0.34 per
Mcf below NYMEX in the fourth quarter, compared to US$0.48 per Mcf in the previous quarter.
Enerplus' Marcellus natural gas price differential for the full
year 2018 averaged US$0.43 per Mcf
below NYMEX, a 43% improvement year-over-year primarily driven by
improved pipeline takeaway capacity in the Marcellus region.
Operating expenses in the fourth quarter and full year 2018 were
$6.99 per BOE and $7.00 per BOE, respectively. Full year 2018
operating expenses were $0.63 per BOE
higher year-over-year primarily due to the Company's higher liquids
production weighting, which increased to 54% in 2018 from 48% in
2017.
Transportation costs in the fourth quarter and full year 2018
were $3.71 per BOE and $3.63 per BOE, respectively. Full year 2018
transportation costs were approximately flat compared to 2017.
Cash general and administrative ("G&A") expenses in the
fourth quarter and full year 2018 were $1.40 per BOE and $1.47 per BOE, respectively. Full year 2018 cash
G&A expenses per BOE were 10% lower compared to 2017.
Capital Expenditures and Balance Sheet
Position
Capital spending was $72.1
million in the fourth quarter of 2018, bringing full year
2018 capital spending to $593.9
million, in-line with the Company's $585 million 2018 budget.
Enerplus remains in a strong financial position. The Company's
total debt net of cash at December 31,
2018 was $333.5 million,
comprised of $696.8 million of senior
notes less $363.3 million in cash. At
December 31, 2018, Enerplus was
undrawn on its $800 million bank
credit facility and had a net debt to adjusted funds flow ratio of
0.4 times.
Share Repurchases
During 2018 Enerplus repurchased
5,925,084 common shares at an average share price of $13.33 and a cost of $79.0
million. Subsequent to 2018 and up to February 20, 2019, the Company spent $6.7 million repurchasing 586,953 common shares
at an average price of $11.40 per
share.
The Company received approval from the board of directors to
renew the Normal Course Issuer Bid upon expiry of the existing term
on March 25th, 2019,
subject to approval by the Toronto Stock Exchange ("TSX"). The
proposed renewal will be for 7% of public float (within the meaning
under the TSX rules) consistent with the current bid.
2018 RESERVES SUMMARY
- Replaced 194% of 2018 production, adding 65.7 MMBOE (51% 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 244% of 2018 North Dakota production, adding 35.1 MMBOE of
2P reserves and 247% of 2018 Marcellus production, adding 187.4 Bcf
of 2P reserves (including revisions and economic factors).
- F&D costs were $13.08 per BOE
for proved developed producing ("PDP") reserves, $16.69 per BOE for proved reserves, and
$13.74 per BOE for 2P reserves,
including future development costs ("FDC").
- Three-year average F&D costs were $10.17 per BOE for PDP reserves, $10.27 per BOE for proved reserves, and
$10.04 per BOE for 2P reserves,
including FDC.
- Finding, development and acquisition ("FD&A") costs were
$17.42 per BOE for proved reserves
and $14.37 per BOE for 2P reserves,
including FDC.
- Three-year average FD&A costs were $7.55 per BOE for proved reserves and
$8.26 per BOE for 2P reserves,
including FDC.
- Total 2P reserves were 427.7 MMBOE at year-end 2018,
representing an 8% increase from year-end 2017.
- 2P reserves were comprised of 49% crude oil, 5% natural gas
liquids, and 46% natural gas at year-end 2018.
- Proved developed producing reserves and total proved reserves
represent 46% and 70% of 2P reserves, respectively.
ASSET ACTIVITY
Williston
Basin
Williston Basin
production averaged 47,420 BOE per day (83% oil) during the fourth
quarter, 2% higher than the prior quarter. Fourth quarter
Williston Basin production was
comprised of 44,201 BOE per day in North
Dakota and 3,219 BOE per day in Montana. Full year 2018 production from
North Dakota averaged 39,659 BOE
per day, a 42% increase year-over-year.
In the fourth quarter the Company drilled 12 gross operated
wells (74% average working interest) and brought one gross operated
well (100% working interest) on production.
As previously indicated, Enerplus expects North Dakota production to decline in the
first quarter of 2019 due to modest fourth quarter completions
activity and the Company's decision to slow completions early in
2019 as a result of significant oil price volatility. Following
this, production is expected to meaningfully increase with strong
growth forecast for the second half of 2019.
Marcellus
Marcellus production averaged 211 MMcf per
day during the fourth quarter, approximately flat to the prior
quarter. Full year 2018 production averaged 208 MMcf per day, a 5%
increase year-over-year.
In the fourth quarter the Company participated in drilling 15
gross non-operated wells (11% average working interest) with 30
gross non-operated wells (5% average working interest) brought on
production. At the time of this news release, 28 of these wells had
more than 30 days on production. These wells had an average
completed lateral length of 6,950 feet per well and average peak
30-day production rates per well of 18.1 MMcf per day.
Canadian Waterfloods
Canadian waterflood production
averaged 9,731 BOE per day (93% oil) during the fourth quarter,
modestly higher than the prior quarter. Full year 2018 production
averaged 9,897 BOE per day, a reduction of approximately 3,050 BOE
per day year-over-year primarily due to the sale of waterflood
assets throughout 2017.
Average Daily Production(1)
|
Three months
ended December 31, 2018
|
|
Twelve months
ended December 31, 2018
|
|
Crude Oil
(Mbbl/d)
|
NGL
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
(Mboe/d)
|
|
Crude Oil
(Mbbl/d)
|
NGL
(Mbbl/d)
|
Natural
gas
(MMcf/d)
|
Total
(Mboe/d)
|
Williston
Basin
|
39.5
|
3.5
|
26.2
|
47.4
|
|
35.5
|
3.4
|
24.3
|
43.0
|
Marcellus
|
-
|
-
|
210.8
|
35.1
|
|
-
|
-
|
208.0
|
34.7
|
Canadian
Waterfloods
|
9.0
|
0.1
|
3.5
|
9.7
|
|
9.1
|
0.1
|
4.1
|
9.9
|
Other(2)
|
1.4
|
0.9
|
19.9
|
5.6
|
|
0.8
|
1.0
|
23.5
|
5.7
|
Total
|
50.0
|
4.5
|
260.4
|
97.8
|
|
45.4
|
4.5
|
259.8
|
93.2
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended December 31, 2018
|
|
Twelve months
ended December 31, 2018
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
1
|
1.0
|
|
1
|
0.2
|
|
38
|
32.8
|
|
10
|
2.7
|
Marcellus
|
-
|
-
|
|
30
|
1.5
|
|
-
|
-
|
|
64
|
6.7
|
Canadian
Waterfloods
|
4
|
2.9
|
|
6
|
0.0
|
|
6
|
4.8
|
|
7
|
0.0
|
Other(2)
|
-
|
-
|
|
4
|
0.3
|
|
4
|
3.7
|
|
7
|
1.2
|
Total
|
5
|
3.9
|
|
41
|
2.1
|
|
48
|
41.3
|
|
88
|
10.6
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises DJ Basin
and non-core properties in Canada.
|
2019 GUIDANCE
Enerplus' previously announced and
unchanged 2019 guidance is provided below.
Capital
spending
|
$565 to $635
million
|
Average annual
production
|
94,000 to 100,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
52,500 to 56,000
bbl/d
|
Average royalty and
production tax rate
|
25%
|
Operating
expense
|
$8.00/BOE
|
Transportation
expense
|
$4.00/BOE
|
Cash G&A
expense
|
$1.50/BOE
|
2019 Differential/Basis Outlook(1)
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(4.00)/bbl
|
Marcellus basis
(compared to NYMEX natural gas)
|
US$(0.30)/Mcf
|
(1) Excluding transportation
costs.
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED FINANCIAL RESULTS
|
December 31,
|
|
December 31,
|
|
2018
|
2017
|
|
2018
|
2017
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
Net Income
|
$
|
249,315
|
$
|
15,272
|
|
$
|
378,279
|
$
|
236,998
|
Cash Flow from
Operating Activities
|
|
221,619
|
|
135,332
|
|
|
738,784
|
|
476,125
|
Adjusted Funds
Flow(4)
|
|
214,285
|
|
199,559
|
|
|
753,506
|
|
524,064
|
Dividends to
Shareholders - Declared
|
|
7,234
|
|
7,264
|
|
|
29,256
|
|
29,033
|
Total Debt Net of
Cash(4)
|
|
333,523
|
|
325,831
|
|
|
333,523
|
|
325,831
|
Capital
Spending
|
|
72,058
|
|
116,827
|
|
|
593,876
|
|
458,015
|
Property and Land
Acquisitions
|
|
9,474
|
|
3,805
|
|
|
25,840
|
|
13,276
|
Property
Divestments
|
|
886
|
|
(1,385)
|
|
|
6,912
|
|
56,196
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.4x
|
|
0.6x
|
|
|
0.4x
|
|
0.6x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net Income -
Basic
|
$
|
1.03
|
$
|
0.06
|
|
$
|
1.55
|
$
|
0.98
|
Net Income -
Diluted
|
|
1.02
|
|
0.06
|
|
|
1.53
|
|
0.96
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
242,344
|
|
242,129
|
|
|
244,076
|
|
241,929
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
245,242
|
|
248,122
|
|
|
247,261
|
|
247,874
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
Oil &
Natural Gas Sales(3)
|
$
|
45.43
|
$
|
41.72
|
|
$
|
47.35
|
$
|
36.93
|
Royalties and
Production Taxes
|
|
(11.58)
|
|
(10.65)
|
|
|
(11.92)
|
|
(8.91)
|
Commodity Derivative
Instruments
|
|
(0.31)
|
|
(0.39)
|
|
|
(1.05)
|
|
0.28
|
Cash Operating
Expenses
|
|
(6.99)
|
|
(6.42)
|
|
|
(7.00)
|
|
(6.39)
|
Transportation
Costs
|
|
(3.71)
|
|
(3.20)
|
|
|
(3.63)
|
|
(3.60)
|
General and
Administrative Expenses
|
|
(1.40)
|
|
(1.55)
|
|
|
(1.47)
|
|
(1.63)
|
Cash Share-Based
Compensation
|
|
0.23
|
|
(0.01)
|
|
|
(0.01)
|
|
(0.03)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(0.90)
|
|
(1.17)
|
|
|
(0.92)
|
|
(1.24)
|
Current Income Tax
Recovery
|
|
3.03
|
|
6.15
|
|
|
0.80
|
|
1.55
|
Adjusted Funds
Flow(4)
|
$
|
23.80
|
$
|
24.48
|
|
$
|
22.15
|
$
|
16.96
|
|
|
|
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED OPERATING RESULTS
|
December 31,
|
|
December 31,
|
|
2018
|
2017
|
|
2018
|
2017
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
49,968
|
|
42,374
|
|
|
45,424
|
|
36,935
|
Natural Gas Liquids
(bbls/day)
|
|
4,483
|
|
4,448
|
|
|
4,486
|
|
3,858
|
Natural Gas
(Mcf/day)
|
|
260,453
|
|
250,607
|
|
|
259,837
|
|
263,506
|
Total
(BOE/day)
|
|
97,860
|
|
88,590
|
|
|
93,216
|
|
84,711
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
56%
|
|
53%
|
|
|
54%
|
|
48%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
$
|
64.18
|
$
|
65.91
|
|
$
|
74.59
|
$
|
58.69
|
Natural Gas Liquids
(per bbl)
|
|
26.72
|
|
32.26
|
|
|
28.31
|
|
30.01
|
Natural Gas
(per Mcf)
|
|
4.28
|
|
3.03
|
|
|
3.42
|
|
3.21
|
(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, 2018 ("2018
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 2018 MD&A.
|
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 95% of the net present value (discounted at 10%,
before tax, using January 1, 2019
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 70% of the net present value
(discounted at 10%, before tax, using the average commodity price
forecasts and inflation rates of McDaniel, GLJ Petroleum
Consultants ("GLJ") and Sproule Associates Limited ("Sproule") as
of January 1, 2019) of the Company's
2P reserves located in Canada and
all of the reserves associated with the Company's properties
located in North Dakota,
Montana and Colorado. The Company has evaluated the
remaining 30% 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 also used the average commodity price
forecasts and inflation rates of McDaniel, GLJ and Sproule as of
January 1, 2019 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, 2018 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
|
9,062
|
17,969
|
58,284
|
85,315
|
8,443
|
28,707
|
591,890
|
197,191
|
Proved developed
non-producing
|
15
|
135
|
921
|
1,071
|
138
|
2,213
|
3,748
|
2,202
|
Proved
undeveloped
|
560
|
3,077
|
47,325
|
50,962
|
5,202
|
88
|
253,426
|
98,416
|
Total
proved
|
9,637
|
21,181
|
106,530
|
137,347
|
13,783
|
31,007
|
849,063
|
297,809
|
Total
probable
|
3,024
|
7,215
|
60,631
|
70,869
|
7,277
|
10,129
|
300,449
|
129,909
|
Proved plus
Probable
|
12,660
|
28,395
|
167,160
|
208,216
|
21,060
|
41,137
|
1,149,511
|
427,718
|
Net
|
|
|
|
|
|
|
|
|
Proved
producing
|
7,514
|
15,506
|
46,815
|
69,835
|
6,875
|
29,245
|
475,633
|
160,856
|
Proved developed
non-producing
|
14
|
124
|
751
|
889
|
103
|
2,081
|
3,039
|
1,845
|
Proved
undeveloped
|
489
|
2,560
|
37,881
|
40,930
|
4,166
|
73
|
200,992
|
78,606
|
Total
proved
|
8,017
|
18,189
|
85,447
|
111,654
|
11,143
|
31,399
|
679,664
|
241,307
|
Total
probable
|
2,387
|
5,985
|
48,509
|
56,881
|
5,865
|
10,168
|
238,514
|
104,194
|
Proved plus
Probable
|
10,404
|
24,174
|
133,956
|
168,535
|
17,008
|
41,567
|
918,178
|
345,501
|
Reserves Reconciliation
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a gross basis, from
December 31, 2017 to December 31, 2018.
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, 2017
|
8,890
|
22,552
|
91,101
|
122,543
|
13,000
|
55,992
|
803,018
|
278,712
|
Acquisitions
|
-
|
-
|
175
|
175
|
23
|
-
|
114
|
217
|
Dispositions
|
(2)
|
-
|
(239)
|
(242)
|
(96)
|
(6,447)
|
(126)
|
(1,433)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
1,501
|
500
|
21,485
|
23,485
|
2,292
|
976
|
77,554
|
38,866
|
Economic
factors
|
64
|
127
|
(84)
|
107
|
(99)
|
(1,597)
|
(1,240)
|
(465)
|
Technical
revisions
|
1,007
|
(437)
|
7,236
|
7,806
|
232
|
(8,602)
|
54,558
|
15,697
|
Production
|
(1,823)
|
(1,560)
|
(13,144)
|
(16,527)
|
(1,570)
|
(9,314)
|
(84,814)
|
(33,785)
|
Proved Reserves
at
Dec. 31, 2018
|
9,637
|
21,181
|
106,530
|
137,347
|
13,783
|
31,007
|
849,063
|
297,809
|
|
|
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, 2017
|
2,719
|
7,635
|
58,125
|
68,479
|
7,752
|
21,289
|
233,742
|
118,737
|
Acquisitions
|
-
|
-
|
39
|
39
|
5
|
-
|
26
|
48
|
Dispositions
|
(1)
|
-
|
(65)
|
(66)
|
(42)
|
(2,293)
|
(37)
|
(496)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
1,150
|
1,023
|
13,675
|
15,848
|
1,397
|
395
|
70,598
|
29,077
|
Economic
factors
|
(109)
|
25
|
(71)
|
(155)
|
(95)
|
(1,523)
|
549
|
(413)
|
Technical
revisions
|
(735)
|
(1,468)
|
(11,073)
|
(13,276)
|
(1,739)
|
(7,739)
|
(4,430)
|
(17,043)
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Probable Reserves
at
Dec. 31, 2018
|
3,024
|
7,215
|
60,631
|
70,869
|
7,277
|
10,129
|
300,449
|
129,909
|
|
|
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, 2017
|
11,609
|
30,187
|
149,227
|
191,023
|
20,752
|
77,281
|
1,036,760
|
397,448
|
Acquisitions
|
-
|
-
|
214
|
214
|
28
|
-
|
139
|
265
|
Dispositions
|
(3)
|
-
|
(305)
|
(307)
|
(137)
|
(8,741)
|
(162)
|
(1,929)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
2,651
|
1,522
|
35,160
|
39,333
|
3,689
|
1,372
|
148,152
|
67,943
|
Economic
factors
|
(45)
|
152
|
(155)
|
(48)
|
(194)
|
(3,120)
|
(691)
|
(878)
|
Technical
revisions
|
272
|
(1,906)
|
(3,836)
|
(5,470)
|
(1,507)
|
(16,341)
|
50,129
|
(1,346)
|
Production
|
(1,823)
|
(1,560)
|
(13,144)
|
(16,527)
|
(1,570)
|
(9,314)
|
(84,814)
|
(33,785)
|
Proved Plus
Probable
Reserves at Dec. 31, 2018
|
12,660
|
28,395
|
167,160
|
208,216
|
21,060
|
41,137
|
1,149,511
|
427,718
|
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)
|
|
2019
|
656
|
714
|
2020
|
527
|
543
|
2021
|
106
|
524
|
2022
|
34
|
163
|
2023
|
13
|
65
|
2024
|
6
|
7
|
Remainder
|
5
|
6
|
Total FDC
Undiscounted
|
1,348
|
2,022
|
Total FDC
Discounted at 10%
|
1,213
|
1,739
|
F&D and
FD&A Costs – including future development
costs
|
|
($ millions except
for per BOE amounts)
|
2018
|
2017
|
2016
|
3
Year
|
Proved Plus
Probable Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$593.8
|
$458.0
|
$209.1
|
$1,260.9
|
Net change in Future
Development Costs
|
$309.1
|
$102.8
|
$(4.0)
|
$407.9
|
Gross Reserves
additions (MMBOE)
|
65.7
|
58.0
|
42.6
|
166.3
|
F&D costs
($/BOE)
|
$13.74
|
$9.68
|
$4.82
|
$10.04
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$612.7
|
$415.1
|
$(335.1)
|
$692.7
|
Net change in Future
Development Costs
|
$308.1
|
$85.1
|
$(94.5)
|
$298.6
|
Gross Reserves
additions (MMBOE)
|
64.1
|
45.6
|
10.3
|
119.9
|
FD&A costs
($/BOE)
|
$14.37
|
$10.98
|
$(41.60)
|
$8.26
|
|
|
|
|
|
Proved
Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$593.8
|
$458.0
|
$209.1
|
$1,260.9
|
Net change in Future
Development Costs
|
$309.3
|
$114.0
|
$(124.4)
|
$298.9
|
Gross Reserves
additions (MMBOE)
|
54.1
|
50.5
|
47.2
|
151.9
|
F&D costs
($/BOE)
|
$16.69
|
$11.32
|
$1.79
|
$10.27
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$612.7
|
$415.1
|
$(335.1)
|
$692.7
|
Net change in Future
Development Costs
|
$308.3
|
$96.7
|
$(202.1)
|
$202.9
|
Gross Reserves
additions (MMBOE)
|
52.9
|
41.0
|
24.7
|
118.6
|
FD&A costs
($/BOE)
|
$17.42
|
$12.48
|
$(21.74)
|
$7.55
|
|
|
|
|
|
Proved Developed
Producing Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$593.8
|
$458.0
|
$209.1
|
$1,260.9
|
Gross Reserves
additions (MMBOE)
|
45.4
|
34.8
|
43.9
|
124.0
|
F&D costs
($/BOE)
|
$13.08
|
$13.17
|
$4.77
|
$10.17
|
|
|
|
|
|
|
Forecast Price Assumptions
The forecast price and cost case assumes no legislative or
regulatory amendments, and includes the effects of inflation. The
estimated future net revenue to be derived from the production of
the reserves is based on the following average of the price
forecasts of McDaniel, GLJ and Sproule as of January 1, 2019 (utilized by McDaniel, NSAI and
by the Company in its internal evaluations for consistency in the
Company's reserves reporting), and the following inflation and
exchange rate assumptions.
|
WTI
Crude Oil(1)
US$/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
|
|
|
|
|
|
|
|
|
2019
|
58.58
|
67.30
|
43.92
|
3.00
|
1.88
|
0.757
|
0.0
|
2020
|
64.60
|
75.84
|
52.76
|
3.13
|
2.31
|
0.782
|
2.0
|
2021
|
68.20
|
80.17
|
59.10
|
3.33
|
2.74
|
0.797
|
2.0
|
2022
|
71.00
|
83.22
|
61.60
|
3.51
|
3.05
|
0.803
|
2.0
|
2023
|
72.81
|
85.34
|
63.39
|
3.62
|
3.21
|
0.807
|
2.0
|
2024
|
74.59
|
87.33
|
65.14
|
3.70
|
3.31
|
0.808
|
2.0
|
2025
|
76.42
|
89.50
|
66.99
|
3.77
|
3.39
|
0.808
|
2.0
|
2026
|
78.40
|
91.89
|
69.06
|
3.85
|
3.46
|
0.808
|
2.0
|
2027
|
79.98
|
93.76
|
70.60
|
3.92
|
3.54
|
0.808
|
2.0
|
2028
|
81.59
|
95.68
|
72.17
|
4.01
|
3.62
|
0.808
|
2.0
|
2029
|
83.22
|
97.60
|
73.62
|
4.09
|
3.69
|
0.808
|
2.0
|
2030
|
84.89
|
99.55
|
75.09
|
4.17
|
3.77
|
0.808
|
2.0
|
2031
|
86.58
|
101.54
|
76.59
|
4.25
|
3.84
|
0.808
|
2.0
|
2032
|
88.31
|
103.57
|
78.12
|
4.34
|
3.92
|
0.808
|
2.0
|
2033
|
90.08
|
105.64
|
79.68
|
4.42
|
4.00
|
0.808
|
2.0
|
Thereafter
|
(4)
|
(4)
|
(4)
|
(4)
|
(4)
|
0.808
|
(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, 2018, ($ Millions, discounted at)
|
0%
|
5%
|
10%
|
15%
|
Proved developed
producing
|
4,507
|
3,257
|
2,568
|
2,140
|
Proved developed
non-producing
|
17
|
12
|
8
|
6
|
Proved
undeveloped
|
1,714
|
1,057
|
695
|
467
|
Total
Proved
|
6,238
|
4,326
|
3,271
|
2,613
|
Probable
|
3,875
|
2,080
|
1,311
|
911
|
Total Proved Plus
Probable Reserves (before tax)
|
10,113
|
6,405
|
4,582
|
3,523
|
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,
2018. These contingent resources are economic using the
average of the three independent petroleum consulting firms' price
forecasts (McDaniel, GLJ and Sproule) as of January 1, 2019, use established technologies and
are all classified in the "development pending" maturity sub-class.
However, 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' Canadian 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, 2018.
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
|
31.6
|
MMBOE
|
44.2
|
Total
Canada
|
31.6
|
MMBOE
|
44.2
|
United States
Properties
|
|
|
|
Fort Berthold –
Bakken/Three Forks Tight Oil wells
|
70.9
|
MMBOE
|
135.6
|
Marcellus - Shale
gas
|
699.7
|
Bcf
|
53.3
|
Total United
States
|
187.5
|
MMBOE
|
189.0
|
Total
Company
|
219.2
|
MMBOE
|
233.2
|
LIVE CONFERENCE CALL
Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today,
February 22, 2019 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 22,
2019
|
Time:
|
9:00 am MT/11:00 am
ET
|
Dial-In:
|
416-764-8688
|
|
1-888-390-0546 (toll
free)
|
Audiocast:
|
https://event.on24.com/wcc/r/1909686/E4770801B2052FD2C6F7BC8B25C2B413
|
To ensure timely participation in the conference call, callers are
encouraged to dial in 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
Dial-In:
|
416-764-8677
1-888-390-0541 (toll
free)
|
Passcode:
|
121297
|
Electronic copies of Enerplus' 2018 MD&A and Financial
Statements, along with other public information including investor
presentations, are available on the Company's website at
www.enerplus.com. 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.
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 with the exception of reserves BOE measures which
are on a working 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 with the
exception of production utilized to calculate reserves replacement
ratios which are on a working interest basis. 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, 2018, 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, 2018 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 the average of the price
forecasts of McDaniel, GLJ and Sproule as of January 1, 2019. 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, 2018. 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. F&D
costs are presented in Canadian dollars per working interest BOE
unless otherwise specified.
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. FD&A costs are presented in
Canadian dollars per working interest BOE unless otherwise
specified.
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" and "plans" 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
2019 average production volumes, timing thereof 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 2019 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; our
anticipated share repurchases under current and future normal
course issuer bids; capital spending levels in 2019, net debt to
adjusted funds-flow ratio, financial capacity and liquidity and
capital resources to fund capital spending and working capital
requirements.
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 beyond our current
expectations; 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; the availability of third party services; and
the extent of our liabilities. In addition, our 2019 guidance
contained in this news release is based on the following: a WTI
price of US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, and a USD/CDN exchange rate of 1.32.
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 volatility in
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; 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' 2018 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 laws
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted funds
flow", "adjusted net income", "free cash flow" and "net debt to
adjusted funds flow ratio" 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. "Adjusted net income" is
calculated as net income adjusted for unrealized derivative
instrument gain/loss, asset impairment, gain on divestment of
assets, unrealized foreign exchange gain/loss, and the tax effect
of these items. "Free cash flow" is calculated as adjusted funds
flow minus capital spending. "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 cash flow from
operating activities, net earnings and other measures prescribed by
U.S. GAAP, the terms "adjusted funds flow", "adjusted net income",
"free cash 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'
2018 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation