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' 2016 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. 24, 2017 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today
announced financial and operating results for the quarter and year
ended December 31, 2016, along with
year-end 2016 reserves.
President and CEO Ian C. Dundas
stated, "Enerplus delivered another strong performance in 2016
underpinned by consistent operational execution, top quartile
capital efficiencies, and a continued focus on improving the
financial strength of the business. Once again in 2016 the Company
met or exceeded all of its financial and operating targets,
including significantly strengthening the balance sheet having
reduced net debt by $841 million, or
69%, over the course of the year. With the Company's lower cost
structure and improving differentials in the Bakken and Marcellus,
we have seen a step change in the cash flow generating capability
and financial sustainability of the business."
"As we increase activity at our Fort Berthold operations in
2017, we expect to deliver meaningful production growth and strong
economic returns, setting the foundation for a 20% compound annual
liquids production growth rate over the coming three-year
period."
Financial and Operational Highlights
- Fourth quarter 2016 production averaged 88,960 BOE per day,
bringing annual average 2016 production to 93,125 BOE per day, in
line with guidance of 93,000 BOE per day. Fourth quarter 2016 crude
oil and natural gas liquids production averaged 41,541 barrels per
day, impacted by severe weather in North
Dakota during the quarter. Annual average 2016 liquids
production was 43,256 barrels per day, within the guidance range of
43,000 to 44,000 barrels per day.
- Enerplus realized strong value from its non-core divestments in
2016, selling 13,500 BOE per day (60% natural gas) of production
for aggregate proceeds of $670.4
million.
- The Company reported fourth quarter 2016 net income of
$840.3 million, or $3.43 per diluted share. Net income was impacted
by a gain on the sale of the Company's non-operated North Dakota properties of $339.4 million, and a non-cash deferred tax
recovery of $567.8 million primarily
as a result of the reversal of a portion of the valuation allowance
on the Company's deferred tax asset. For the year ended
December 31, 2016, Enerplus reported
net income of $397.4 million, or
$1.72 per diluted share, compared
with a net loss of $1,523.4 million,
or $7.39 per share, for the
comparable 2015 period.
- Enerplus generated fourth quarter 2016 adjusted funds flow of
$107.7 million, an increase of 34%
from the previous quarter as a result of stronger commodity prices
in the fourth quarter. The Company generated full year 2016
adjusted funds flow of $305.6
million, down 38% from the comparable 2015 period due to
lower average commodity prices and lower hedging gains in 2016.
- Enerplus delivered strong operating cost performance in 2016
reflecting efficiency improvements and the divestment of higher
cost properties. Fourth quarter operating expenses were
$7.15 per BOE, a reduction of 18%
compared to the same period in 2015. Full year 2016 operating
expenses were $7.27 per BOE, a
reduction of 17% compared to 2015.
- Fourth quarter 2016 cash G&A expenses were $1.63 per BOE, a reduction of 7% compared to the
same period in 2015. Full year 2016 cash G&A expenses were
$1.75 per BOE, a reduction of 16%
compared to 2015. Enerplus' lower G&A cost structure is, in
part, a result of a reduction in staffing levels related to
non-core asset divestments.
- Transportation expense in the fourth quarter of 2016 was
$3.44 per BOE, up slightly from the
previous quarter. Full year 2016 transportation expense was
$3.14 per BOE, a 6% increase from the
prior year period.
- Capital spending in the fourth quarter of 2016 was $57.5 million, with approximately 71% allocated
to North Dakota. Full year 2016
capital spending totaled $209.1
million, slightly below annual 2016 guidance of $215.0 million.
- Enerplus significantly strengthened its balance sheet during
2016 having reduced its total debt, net of cash and restricted
cash, by 69%, or $840.7 million, over
the twelve-month period. Total debt, net of cash and restricted
cash, at December 31, 2016 was
$375.5 million, and was comprised of
$23.2 million of bank indebtedness
and $745.6 million of senior notes
less $393.3 million in cash,
including $392.0 million in
restricted cash. The restricted cash balance reflects proceeds from
the sale of the Company's non-operated North Dakota properties which were placed in
escrow in order to facilitate possible future like-kind
transactions in accordance with U.S. federal tax regulations. Net
debt to adjusted funds flow at year-end was 1.2 times.
2016 Reserves Highlights
- Replaced 126% of 2016 production, adding 42.6 MMBOE (42% crude
oil and natural gas liquids) of proved plus probable ("2P")
reserves from development activities (including revisions).
- Material reserves growth was realized in Enerplus' North Dakota and Marcellus assets. The Company
replaced 207% of 2016 North Dakota production, excluding production
from Enerplus' non-operated North
Dakota assets which were sold at the end of 2016, adding
17.5 MMBOE of 2P reserves (including revisions). The Company also
replaced 175% of 2016 Marcellus production, adding 125.0 Bcf of 2P
reserves (including revisions).
- Finding and development ("F&D") costs for proved developed
producing ("PDP") reserves decreased by 60% to $4.77 per BOE for 2016, generating a PDP reserves
recycle ratio of 2.0 times based on a 2016 operating netback
(before hedging) of $9.66 per BOE.
Enerplus' three-year average PDP reserves F&D cost was
$10.37 per BOE.
- F&D costs for 2P reserves decreased by 43% to $4.82 per BOE for 2016, including future
development costs ("FDC"), generating a 2P reserves recycle ratio
of 2.0 times. Enerplus' three-year average 2P reserves F&D
cost, including FDC, was $8.11
per BOE.
- Enerplus sold various non-core properties in 2016 representing
37.3 MMBOE of 2P reserves at a combined value of $20.38 per BOE. Total 2P reserves, net of
divestments, were 382.5 MMBOE at year-end 2016, representing a 6%
decrease from year-end 2015. Excluding acquisitions and
divestments, 2P reserves increased by 2% in 2016.
- 2P reserves were comprised of 51% crude oil and natural gas
liquids and 49% natural gas at year-end 2016.
- Total proved reserves account for 70% of 2P reserves. PDP
reserves represent 71% of total proved reserves and 50% of 2P
reserves.
Operational Overview
2016 PRODUCTION
& CAPITAL SPENDING
|
|
Q4
2016
Average
Production
|
2016
Annual
Average
Production
|
2016
Capital
Spending
($million)
|
Crude Oil &
NGLs (bbls/day)
|
|
|
|
Canada
|
13,577
|
14,497
|
$44.4
|
United
States
|
27,964
|
28,759
|
$140.4
|
Total Crude Oil
& NGLs (bbls/day)
|
41,541
|
43,256
|
$184.8
|
Natural Gas
(Mcf/day)
|
|
|
|
Canada
|
68,437
|
79,057
|
-
|
United
States
|
216,078
|
220,157
|
$24.3
|
Total Natural Gas
(Mcf/day)
|
284,515
|
299,214
|
$24.3
|
Company Total
(BOE/day)
|
88,960
|
93,125
|
$209.1
|
2016 NET DRILLING
ACTIVITY(1)
|
|
Wells
Drilled
|
Wells
On-stream
|
Crude
Oil
|
|
|
Canada(2)
|
8.0
|
6.0
|
United
States
|
16.0
|
16.1
|
Total Crude
Oil
|
24.0
|
22.1
|
Natural
Gas
|
|
|
Canada
|
-
|
-
|
United
States
|
1.3
|
5.2
|
Total Natural
Gas
|
1.3
|
5.2
|
Company
Total
|
25.3
|
27.3
|
(1) Table may not add due to
rounding.
|
(2) Includes injector
wells.
|
Asset Activity
WILLISTON BASIN
Williston Basin production
averaged 31,981 BOE per day in the fourth quarter of 2016, a
decrease of 3% from the prior quarter largely due to severe weather
affecting operations at Fort Berthold in North Dakota at the end of the quarter.
Production from North Dakota in
the fourth quarter averaged 27,391 BOE per day, a decrease of 5%
from the prior quarter. As previously announced, Enerplus completed
the sale of approximately 5,000 BOE per day of non-operated
North Dakota production at the end
of the fourth quarter. Full year 2016 production from the
Williston Basin averaged 32,888
BOE per day, approximately flat to 2015 average production.
Capital spending in North
Dakota in the fourth quarter of 2016 was $41.1 million. At Fort Berthold, Enerplus drilled
three net wells and brought 3.6 net wells on production during the
fourth quarter. Enerplus completed three operated wells in the
fourth quarter, which were part of a density test comprising two
Middle Bakken wells spaced at 500 feet offset by one First Bench
Three Forks well at 700 feet. The average initial 30-day production
rate from the two Middle Bakken wells was 1,667 BOE per day with
continued strong production over the initial 90-day period
averaging over 1,200 BOE per day. The initial 30-day production
rate of the First Bench Three Forks well was 1,530 BOE per day and
the initial 90-day production rate was also over 1,200 BOE per day.
These results further support Enerplus' revised development plan of
approximately ten wells per drilling spacing unit.
In 2016, Enerplus drilled 13 net operated wells (16 gross) and
brought 13 net operated wells (17 gross) on production. The average
total operated well cost (drill, complete, and facilities) in 2016
for a 10,000 foot lateral was US$8.0
million. Including non-operated wells, total net wells
drilled in 2016 were 16 and total net wells completed were 16. With
the ramp-up in activity at Fort Berthold in 2017, Enerplus expects
to drill approximately 26 net operated wells (34 gross) and bring
28 net operated wells (36 gross) on production under a two rig
program. This is projected to drive 50% production growth in
North Dakota from the beginning of
2017 through the fourth quarter.
Enerplus estimates that it has protected approximately 75% of
its 2017 North Dakota capital program from cost escalation through
service contracting. The Company is budgeting for an
US$8.0 million total well cost in
2017 for a 10,000 foot lateral under its base completion design of
1,000 pounds of proppant per lateral foot.
Enerplus ended 2016 with approximately 11 net drilled
uncompleted wells in North
Dakota.
Enerplus' Bakken crude oil price realizations continued to
improve in 2016 due to declining basin production and
strong regional refinery demand. Enerplus' realized
Bakken differential below WTI improved by 21% year over year,
averaging US$7.46 per barrel in 2016
compared to US$9.44 per barrel in
2015. In the fourth quarter of 2016, Enerplus' Bakken differential
averaged US$6.80 per barrel below
WTI. With the expectation that the Dakota Access Pipeline will be
completed and in service around mid-year 2017, increasing regional
takeaway capacity, Enerplus is improving its forecast 2017 Bakken
crude oil differential to US$4.50 per
barrel below WTI, from its previous guidance of US$6.00 per barrel below WTI.
MARCELLUS
Marcellus production averaged 192 MMcf per day in the fourth
quarter of 2016, a decrease of 6% from the prior quarter. Enerplus
estimates that it had approximately 30 MMcf per day of production
curtailed during October 2016 due to
low natural gas prices resulting from high regional storage
inventories combined with seasonal demand weakness. Regional
Marcellus natural gas prices strengthened in November 2016 and production has been at or close
to full capacity since that time.
There was minimal drilling activity in the Marcellus during
2016, with capital activity largely focused on bringing drilled
uncompleted wells on production. During the latter part of the
fourth quarter of 2016, in response to improving natural gas
prices, a modest level of drilling activity recommenced with
Enerplus participating in drilling approximately one net well with
one net well brought on production. Capital spending in the fourth
quarter was $4.2 million. In total,
Enerplus participated in drilling one net well in 2016 and
approximately five net wells that were brought on production. Full
year 2016 production from the Marcellus averaged 195 MMcf per day,
approximately 4% lower than 2015 average production.
Enerplus ended 2016 with approximately four net drilled
uncompleted wells in the Marcellus.
Enerplus' realized Marcellus differential improved in 2016 to
US$0.93 per Mcf below NYMEX, compared
to US$1.37 per Mcf below NYMEX in
2015. Lower capital spending in the region combined with
growing regional gas fired power demand and continued pipeline
capacity additions have helped to alleviate some of the
transportation constraints in the region. In the fourth quarter of
2016, despite weak pricing in October, Enerplus' realized Marcellus
differential averaged US$0.88 per Mcf
below NYMEX. The recent improvement in Marcellus natural gas prices
is expected to drive a moderate return to drilling activity in
2017. Enerplus is forecasting 2017 drilling activity of
approximately eight net wells and bringing six net wells on
production, for total capital spending of $60 million. With the current strength in NYMEX
natural gas prices and Enerplus' forecast average 2017 Marcellus
differential of US$0.90 per Mcf, the
Marcellus is expected to generate meaningful free cash flow in
2017.
CANADIAN WATERFLOODS
Canadian waterflood production averaged 15,748 BOE per day in
the fourth quarter of 2016, an increase of 7% from the prior
quarter largely due to the acquisition of the Ante Creek property,
which closed mid-way through the fourth quarter. Full year
2016 production from the Canadian waterfloods averaged 16,137 BOE
per day, a decrease of approximately 16% from 2015 reflecting the
divestment of properties in the Peace River Arch area in
June 2016 and lower capital spending
in 2016.
Fourth quarter 2016 capital spending in the waterfloods was
$10.2 million with full year 2016
capital spending of $44.4 million, a
60% reduction in spending year over year. 2016 capital spending was
focused on the expansion and development of existing waterfloods,
sustaining polymer injection at Medicine Hat Glauc 'C' and
Giltedge, and maintenance activities. Enerplus is budgeting
moderately higher spending in the waterflood portfolio in 2017 at
$60 million. Capital activity in 2017
will be predominately focused on waterflood optimization and
expansion at Cadogan and Southeast
Saskatchewan, ongoing polymer injection at Medicine Hat
Glauc 'C' and Giltedge, and ramping up water injection at Ante
Creek where Enerplus plans to be injecting from eight wells by
year-end.
Enerplus' high-margin, low decline Canadian waterflood portfolio
is expected to continue to be a strong cash flow generator in 2017.
At US$55 per barrel WTI, Enerplus is
forecasting approximately $150
million in net operating income from its
waterflood assets in 2017.
Risk Management
Enerplus continues to protect its capital plans through
commodity hedging. Using swaps and collar structures, Enerplus has
an average of 18,000 barrels per day of crude oil protected in 2017
(approximately 63% of forecast crude oil production net of
royalties), 12,500 barrels per day of crude oil protected in 2018,
and 4,000 barrels per day of crude oil protected in 2019.
Commodity Hedging
Detail (As at February 23, 2017)
|
|
WTI Crude Oil
(US$/bbl)
|
NYMEX
Natural Gas
(US$/Mcf)
|
|
Jan 1, 2017 –
Jun 30, 2017
|
Jul 1, 2017 –
Dec 31, 2017
|
Jan 1, 2018 –
Dec 31, 2018
|
Jan 1, 2019 –
Mar 31, 2019
|
Apr 1, 2019 –
Dec 31, 2019
|
Jan 1, 2017 –
Dec 31, 2017
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
Sold Swaps
|
$53.50
|
$53.50
|
$53.73
|
$53.73
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
2,000
|
2,000
|
3,000
|
3,000
|
-
|
-
|
|
|
|
|
|
|
|
Three-Way
Collars
|
|
|
|
|
|
|
Sold Puts
|
$38.94
|
$39.62
|
$43.13
|
$45.00
|
$43.75
|
$2.06
|
Volume (bbls/d or
Mcf/d)
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
Purchased
Puts
|
$50.29
|
$50.61
|
$54.00
|
$56.00
|
$54.69
|
$2.75
|
Volume (bbls/d or
Mcf/d)
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
|
|
|
|
|
|
|
Sold Calls
|
$61.14
|
$60.33
|
$63.09
|
$70.00
|
$66.18
|
$3.41
|
Volume (bbls/d or
Mcf/d)
|
14,000
|
18,000
|
9,500
|
1,000
|
4,000
|
50,000
|
2017 Guidance
Enerplus' previously announced 2017 guidance is provided below,
including its updated Bakken crude oil differential assumption of
US$4.50 per barrel below WTI (from
US$6.00 per barrel below WTI
previously).
|
|
Capital
spending
|
$450
million
|
Average annual
production
|
86,000 – 90,000 BOE
per day
|
Q4 average
production
|
92,000 – 97,000 BOE
per day
|
Average annual crude
oil and natural gas liquids production
|
40,000 – 43,000 bbls
per day
|
Q4 average crude oil
and natural gas liquids production
|
45,000 – 50,000 bbls
per day
|
Average royalty and
production tax rate
|
23%
|
Operating
expense
|
$7.85 per
BOE
|
Transportation
expense
|
$3.90 per
BOE
|
Cash G&A
expense
|
$1.80 per
BOE
|
2017
Differential/Basis Outlook(1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(4.50) per
bbl
|
Marcellus basis
(compared to NYMEX natural gas)
|
US$(0.90) per
Mcf
|
(1) Before field
transportation costs.
|
Selected Financial and Operating Results
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months
ended
|
SELECTED FINANCIAL RESULTS
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
2016
|
|
2015
|
Financial
(000's)
|
|
|
|
|
|
|
|
|
|
Adjusted Funds
Flow(4)
|
$
|
107,730
|
$
|
102,674
|
|
$
|
305,605
|
$
|
493,101
|
Dividends to
Shareholders
|
|
7,214
|
|
22,717
|
|
|
35,439
|
|
131,955
|
Net
Income/(Loss)
|
|
840,325
|
|
(624,987)
|
|
|
397,416
|
|
(1,523,403)
|
Debt
Outstanding net of cash and restricted cash
|
|
375,520
|
|
1,216,184
|
|
|
375,520
|
|
1,216,184
|
Capital
Spending
|
|
57,462
|
|
89,490
|
|
|
209,135
|
|
493,403
|
Property and Land
Acquisitions
|
|
118,452
|
|
8,794
|
|
|
126,126
|
|
9,552
|
Property
Divestments
|
|
389,750
|
|
83,236
|
|
|
670,364
|
|
286,614
|
Debt to Adjusted
Funds Flow Ratio(4)
|
|
1.2x
|
|
2.5x
|
|
|
1.2x
|
|
2.5x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) -
Basic
|
$
|
3.49
|
$
|
(3.03)
|
|
$
|
1.75
|
$
|
(7.39)
|
Net Income/(Loss) -
Diluted
|
|
3.43
|
|
(3.03)
|
|
|
1.72
|
|
(7.39)
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
240,483
|
|
206,517
|
|
|
226,530
|
|
206,205
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
Oil &
Natural Gas Sales(3)
|
$
|
32.81
|
$
|
23.81
|
|
$
|
25.88
|
$
|
27.07
|
Royalties and
Production Taxes
|
|
(7.60)
|
|
(4.75)
|
|
|
(5.77)
|
|
(5.63)
|
Commodity Derivative
Instruments
|
|
1.12
|
|
7.50
|
|
|
2.36
|
|
7.40
|
Cash Operating
Expenses
|
|
(7.22)
|
|
(8.68)
|
|
|
(7.31)
|
|
(8.75)
|
Transportation
Costs
|
|
(3.44)
|
|
(2.98)
|
|
|
(3.14)
|
|
(2.95)
|
General and
Administrative Expenses
|
|
(1.63)
|
|
(1.75)
|
|
|
(1.75)
|
|
(2.09)
|
Cash Share-Based
Compensation
|
|
(0.17)
|
|
0.16
|
|
|
(0.09)
|
|
(0.02)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(0.97)
|
|
(2.94)
|
|
|
(1.28)
|
|
(2.78)
|
Current Tax
Recovery
|
|
0.26
|
|
0.07
|
|
|
0.07
|
|
0.43
|
Adjusted Funds
Flow(4)
|
$
|
13.16
|
$
|
10.44
|
|
$
|
8.97
|
$
|
12.68
|
|
|
|
|
|
|
|
Three months
ended
|
|
Twelve months
ended
|
SELECTED OPERATING RESULTS
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
2016
|
|
2015
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
37,128
|
|
41,135
|
|
|
38,353
|
|
41,639
|
Natural Gas Liquids
(bbls/day)
|
|
4,413
|
|
5,092
|
|
|
4,903
|
|
4,763
|
Natural Gas
(Mcf/day)
|
|
284,515
|
|
364,065
|
|
|
299,214
|
|
360,733
|
Total
(BOE/day)
|
|
88,960
|
|
106,905
|
|
|
93,125
|
|
106,524
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
47%
|
|
43%
|
|
|
46%
|
|
44%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
$
|
53.91
|
$
|
43.04
|
|
$
|
44.84
|
$
|
48.43
|
Natural Gas Liquids
(per bbl)
|
|
21.31
|
|
16.61
|
|
|
15.29
|
|
18.06
|
Natural Gas
(per Mcf)
|
|
2.89
|
|
1.89
|
|
|
2.06
|
|
2.15
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
5
|
|
2
|
|
|
25
|
|
46
|
|
|
|
|
|
|
|
|
|
|
(1) Non‑cash amounts have
been excluded.
|
(2) Based on Company interest
production volumes. See "Basis of Presentation" section in
the 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
MD&A.
|
|
Three months
ended
|
|
Twelve months
ended
|
|
December 31,
|
|
December 31,
|
Average Benchmark Pricing
|
2016
|
2015
|
|
2016
|
2015
|
WTI crude oil
(US$/bbl)
|
$
|
49.29
|
$
|
42.18
|
|
$
|
43.32
|
$
|
48.80
|
AECO natural
gas – monthly index (CDN$/Mcf)
|
|
2.81
|
|
2.65
|
|
|
2.09
|
|
2.77
|
AECO natural
gas – daily index (CDN$/Mcf)
|
|
3.09
|
|
2.47
|
|
|
2.16
|
|
2.69
|
NYMEX natural
gas – last day (US$/Mcf)
|
|
2.98
|
|
2.27
|
|
|
2.46
|
|
2.66
|
US/CDN average
exchange rate
|
|
1.33
|
|
1.34
|
|
|
1.32
|
|
1.28
|
Share Trading Summary
|
|
CDN(1) – ERF
|
|
U.S.(2) – ERF
|
For the twelve
months ended December 31, 2016
|
|
(CDN$)
|
|
(US$)
|
High
|
|
$
|
13.55
|
|
$
|
10.33
|
Low
|
|
$
|
2.68
|
|
$
|
1.84
|
Close
|
|
$
|
12.74
|
|
$
|
9.48
|
(1) TSX and other
Canadian trading data combined.
|
(2) NYSE and other
U.S. trading data combined.
|
|
|
|
|
|
2016
Dividends per Share
|
|
CDN$
|
|
US$(1)
|
First Quarter
Total
|
$
|
0.09
|
$
|
0.07
|
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
|
$
|
0.18
|
$
|
0.13
|
(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 86% of the net present value (discounted at 10%,
before tax, using January 1, 2017
forecast prices and costs) of the Company's total 2P reserves.
McDaniel, an independent petroleum consulting firm based in
Calgary, Alberta, has evaluated
properties which comprise approximately 48% of the net present
value (discounted at 10%, before tax, using McDaniel's January 1, 2017 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 and Montana. The Company has evaluated the
remaining 52% 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.
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, 2017 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, 2016 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
|
11,306
|
26,388
|
45,402
|
83,096
|
8,242
|
89,205
|
509,215
|
191,073
|
|
Proved developed
non-producing
|
15
|
-
|
420
|
435
|
17
|
4,839
|
989
|
1,423
|
|
Proved
undeveloped
|
300
|
3,845
|
31,744
|
35,889
|
3,566
|
1,726
|
216,411
|
75,811
|
|
Total
proved
|
11,621
|
30,232
|
77,566
|
119,419
|
11,825
|
95,769
|
726,614
|
268,308
|
|
Total
probable
|
2,645
|
8,721
|
45,432
|
56,798
|
6,273
|
30,521
|
276,169
|
114,186
|
Proved plus
Probable
|
14,265
|
38,953
|
122,998
|
176,216
|
18,098
|
126,290
|
1,002,783
|
382,493
|
Net
|
|
|
|
|
|
|
|
|
|
Proved
producing
|
9,677
|
21,857
|
36,740
|
68,274
|
6,675
|
87,416
|
408,473
|
157,597
|
|
Proved developed
non-producing
|
14
|
-
|
351
|
365
|
12
|
3,966
|
827
|
1,177
|
|
Proved
undeveloped
|
277
|
3,119
|
25,300
|
28,696
|
2,841
|
1,336
|
173,076
|
60,606
|
|
Total
proved
|
9,968
|
24,976
|
62,391
|
97,335
|
9,528
|
92,717
|
582,375
|
219,379
|
|
Total
probable
|
2,246
|
7,057
|
36,561
|
45,864
|
5,057
|
29,140
|
221,281
|
92,658
|
Proved plus
Probable
|
12,214
|
32,033
|
98,952
|
143,199
|
14,585
|
121,857
|
803,657
|
312,036
|
Reserves Reconciliation
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a gross basis, from
December 31, 2015 to December 31, 2016.
For the fourth consecutive year, the Company realized positive
proved plus probable developed producing ("P+PDP") technical
revisions at Fort Berthold and the Marcellus as a result of
continued well outperformance. At Fort Berthold, the negative
2P technical revision is a function of the SEC five-year rule on
converting proved undeveloped locations ("PUDs"). As
Enerplus' program scheduling changes over time, PUDs that were
originally scheduled to be drilled and completed within a certain
period may not fit the current development plan timing and would
therefore need to be removed from the Company's bookings. At
year end 2016 Enerplus replaced 48 of these PUDs that in aggregate
had a lower working interest, leading to the negative 2P technical
revision.
The majority of the negative technical revision in the Probable
reserves table below under the Shale Gas category, reflects the
conversion of Marcellus Probable reserves into Proven reserves.
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, 2015
|
13,871
|
31,705
|
86,202
|
131,778
|
10,704
|
183,564
|
625,081
|
277,255
|
Acquisitions
|
1,765
|
-
|
-
|
1,765
|
24
|
14,162
|
-
|
4,149
|
Dispositions
|
(2,885)
|
-
|
(6,034)
|
(8,919)
|
(1,522)
|
(90,343)
|
(7,110)
|
(26,683)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
100
|
-
|
5,429
|
5,529
|
589
|
-
|
36,268
|
12,163
|
Economic
factors
|
(606)
|
(533)
|
-
|
(1,139)
|
(173)
|
(4,731)
|
(30,053)
|
(7,110)
|
Technical
revisions
|
1,123
|
2,088
|
1,182
|
4,393
|
3,925
|
20,012
|
183,193
|
42,187
|
Production
|
(1,746)
|
(3,027)
|
(9,214)
|
(13,987)
|
(1,722)
|
(26,894)
|
(80,763)
|
(33,653)
|
Proved Reserves
at
Dec. 31, 2016
|
11,621
|
30,232
|
77,566
|
119,419
|
11,825
|
95,769
|
726,614
|
268,307
|
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, 2015
|
3,367
|
9,804
|
45,051
|
58,222
|
4,993
|
53,802
|
338,288
|
128,563
|
Acquisitions
|
373
|
-
|
-
|
373
|
1
|
3,227
|
-
|
911
|
Dispositions
|
(845)
|
-
|
(3,680)
|
(4,525)
|
(622)
|
(29,438)
|
(3,566)
|
(10,648)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
45
|
-
|
13,810
|
13,855
|
1,540
|
-
|
27,948
|
20,053
|
Economic
factors
|
534
|
(193)
|
-
|
341
|
(69)
|
(396)
|
1,998
|
540
|
Technical
revisions
|
(829)
|
(890)
|
(9,749)
|
(11,468)
|
430
|
3,325
|
(88,499)
|
(25,234)
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Probable Reserves
at
Dec. 31, 2016
|
2,645
|
8,721
|
45,432
|
56,798
|
6,273
|
30,521
|
276,169
|
114,186
|
|
|
|
|
|
|
|
|
|
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, 2015
|
17,238
|
41,509
|
131,253
|
190,000
|
15,697
|
237,366
|
963,368
|
405,818
|
Acquisitions
|
2,137
|
-
|
-
|
2,137
|
25
|
17,389
|
-
|
5,060
|
Dispositions
|
(3,730)
|
-
|
(9,713)
|
(13,443)
|
(2,145)
|
(119,781)
|
(10,676)
|
(37,331)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
145
|
-
|
19,239
|
19,384
|
2,129
|
-
|
64,216
|
32,216
|
Economic
factors
|
(72)
|
(726)
|
-
|
(798)
|
(242)
|
(5,127)
|
(28,056)
|
(6,570)
|
Technical
revisions
|
294
|
1,198
|
(8,566)
|
(7,074)
|
4,356
|
23,337
|
94,694
|
16,953
|
Production
|
(1,746)
|
(3,027)
|
(9,214)
|
(13,987)
|
(1,722)
|
(26,894)
|
(80,763)
|
(33,653)
|
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
|
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)
|
|
2017
|
377
|
397
|
2018
|
393
|
478
|
2019
|
97
|
401
|
2020
|
24
|
298
|
2021
|
11
|
15
|
Remainder
|
42
|
40
|
Total FDC
Undiscounted
|
944
|
1,629
|
Total FDC Discounted
at
10%
|
829
|
1,357
|
F&D AND
FD&A COSTS – including future development
costs
|
|
|
($ millions except
for per BOE amounts)
|
2016
|
2015
|
2014
|
3
Year
|
Proved Plus
Probable Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$209.1
|
$493.4
|
$811.0
|
$1,513.6
|
|
Net change in Future
Development Costs
|
$(4.0)
|
$(142.2)
|
$(71.3)
|
$(217.5)
|
|
Gross Reserves
additions (MMBOE)
|
42.6
|
41.6
|
75.5
|
159.7
|
|
F&D costs
($/BOE)
|
$4.82
|
$8.44
|
$9.80
|
$8.11
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$(335.1)
|
$216.2
|
$625.9
|
$507.0
|
|
Net change in Future
Development Costs
|
$(94.5)
|
$(212.5)
|
$(59.2)
|
$(366.3)
|
|
Gross Reserves
additions (MMBOE)
|
10.3
|
14.9
|
65.8
|
91.0
|
|
FD&A costs
($/BOE)
|
$(41.60)
|
$0.25
|
$8.62
|
$1.55
|
Proved
Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$209.1
|
$493.4
|
$811.0
|
$1,513.6
|
|
Net change in Future
Development Costs
|
$(124.4)
|
$210.0
|
$13.8
|
$99.4
|
|
Gross Reserves
additions (MMBOE)
|
47.2
|
50.7
|
69.1
|
167.0
|
|
F&D costs
($/BOE)
|
$1.79
|
$13.88
|
$11.94
|
$9.66
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$(335.1)
|
$216.2
|
$625.9
|
$507.0
|
|
Net change in Future
Development Costs
|
$(202.1)
|
$139.7
|
$4.9
|
$(57.5)
|
|
Gross Reserves
additions (MMBOE)
|
24.7
|
31.1
|
60.9
|
116.7
|
|
FD&A costs
($/BOE)
|
$(21.74)
|
$11.44
|
$10.36
|
$3.85
|
Proved Developed
Producing Reserves
|
|
|
|
|
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
|
Capital
Expenditures
|
$209.1
|
$493.4
|
$811.0
|
$1,513.6
|
|
Gross Reserves
additions (MMBOE)
|
43.9
|
41.5
|
60.7
|
146.0
|
|
F&D costs
($/BOE)
|
$4.77
|
$11.90
|
$13.37
|
$10.37
|
|
|
|
|
|
|
Forecast Price Assumptions
The forecast price and cost case assumes no legislative or
regulatory amendments, and includes the effects of inflation. The
estimated future net revenue to be derived from the production of
the reserves is based on the following price forecasts supplied by
McDaniel as of January 1, 2017, (and
utilized by NSAI and by the Company in its internal evaluations for
consistency in the Corporation's reserves reporting), and the
following inflation and exchange rate assumptions.
McDaniel January
2017 Forecast Price Assumptions
|
|
WTI
Crude Oil(1)
US$/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
|
|
|
|
|
|
|
|
|
2017
|
55.00
|
69.80
|
46.50
|
3.40
|
3.40
|
0.750
|
0.0
|
2018
|
58.70
|
72.70
|
50.50
|
3.20
|
3.15
|
0.775
|
2.0
|
2019
|
62.40
|
75.50
|
54.00
|
3.35
|
3.30
|
0.800
|
2.0
|
2020
|
69.00
|
81.10
|
58.00
|
3.65
|
3.60
|
0.825
|
2.0
|
2021
|
75.80
|
86.60
|
61.90
|
4.00
|
3.90
|
0.850
|
2.0
|
2022
|
77.30
|
88.30
|
63.10
|
4.05
|
3.95
|
0.850
|
2.0
|
2023
|
78.80
|
90.00
|
64.40
|
4.15
|
4.10
|
0.850
|
2.0
|
2024
|
80.40
|
91.80
|
65.60
|
4.25
|
4.25
|
0.850
|
2.0
|
2025
|
82.00
|
93.70
|
67.00
|
4.30
|
4.30
|
0.850
|
2.0
|
2026
|
83.70
|
95.60
|
68.40
|
4.40
|
4.40
|
0.850
|
2.0
|
2027
|
85.30
|
97.40
|
69.60
|
4.50
|
4.50
|
0.850
|
2.0
|
2028
|
87.00
|
99.40
|
71.10
|
4.60
|
4.60
|
0.850
|
2.0
|
2029
|
88.80
|
101.40
|
72.50
|
4.65
|
4.65
|
0.850
|
2.0
|
2030
|
90.60
|
103.50
|
74.00
|
4.75
|
4.75
|
0.850
|
2.0
|
2031
|
92.40
|
105.50
|
75.40
|
4.85
|
4.85
|
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, 2016, ($ Millions, discounted at)
|
0%
|
5%
|
10%
|
15%
|
Proved developed
producing
|
4,021
|
2,767
|
2,117
|
1,730
|
Proved developed
non-producing
|
20
|
11
|
7
|
6
|
Proved
undeveloped
|
1,257
|
700
|
420
|
255
|
Total
Proved
|
5,297
|
3,479
|
2,544
|
1,991
|
Probable
|
3,065
|
1,432
|
820
|
524
|
Total Proved Plus
Probable Reserves (before tax)
|
8,362
|
4,911
|
3,364
|
2,515
|
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,
2016. These contingent resources are economic using
McDaniel's January 1, 2017 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, 2016.
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
|
34.4
|
MMBOE
|
54.3
|
Total
Canada
|
34.4
|
MMBOE
|
54.3
|
United States
Properties
|
|
|
|
Fort Berthold –
Bakken/Three Forks Tight Oil wells
|
119.8
|
MMBOE
|
215.3
|
Marcellus - Shale
gas
|
837.0
|
Bcf
|
96.7
|
Total United
States
|
259.3
|
MMBOE
|
312.0
|
Total
Company
|
293.7
|
MMBOE
|
366.3
|
LIVE CONFERENCE CALL
Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today,
February 24, 2017 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 24,
2017
|
Time:
|
9:00 am MT/11:00 am
ET
|
Dial-In:
|
647-427-7450
|
|
1-888-231-8191 (toll
free)
|
Audiocast:
|
http://event.on24.com/r.htm?e=1347471&s=1&k=96151D7131406EA88FD59E83EC73A3A5
|
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 our 2016 year-end MD&A and Financial
Statements, along with other public information including investor
presentations, are available on our 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.
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, 2016, 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 for the year ended December 31, 2016 ("our AIF") 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, 2017 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, 2016. 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, Enerplus' Wilrich natural gas 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 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", "objective", "ongoing", "may", "will", "project",
"should", "believe", "plans", "intends", "budget", "strategy" and
similar expressions are intended to identify forward-looking
information. In particular, but without limiting the foregoing,
this news release contains forward-looking information pertaining
to the following: expected 2017 average production volumes and the
anticipated production mix; the proportion of our anticipated oil
and gas production that is hedged and the effectiveness of such
hedges in protecting our 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 2017 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 2017, net debt to adjusted funds-flow ratio and
adjusted payout 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 2017 guidance contained
in this news release is based on the following: a WTI price of
US$55.00/bbl, a NYMEX price of
US$3.00/Mcf, an AECO price of
$2.75/GJ and a USD/CDN exchange rate
of 1.35. 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; 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' MD&A and in our other public
filings).
The purpose of disclosure of net operating income from our
Canadian waterflood assets is to assist readers in understanding
our expected and targeted financial results, and this information
may not be appropriate for other purposes. 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", "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'
2016 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation