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' 2019 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. 21, 2020 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported
fourth quarter 2019 cash flow from operating activities of
$188.5 million and adjusted funds
flow of $178.9 million. Enerplus
reported a fourth quarter 2019 net loss of $429.1 million, or $(1.93) per share. The Company recognized a
$451.1 million non-cash goodwill
impairment related to its Canadian reporting unit in the quarter.
Excluding the goodwill impairment and certain other non-cash or
non-recurring items, fourth quarter 2019 adjusted net income was
$34.4 million, or $0.15 per share.
Full year 2019 cash flow from operating activities was
$694.2 million and adjusted funds
flow was $709.0 million. The Company
reported a full year 2019 net loss of $259.7
million, or $(1.12) per share.
Excluding the goodwill impairment and certain other non-cash or
non-recurring items, full year 2019 adjusted net income was
$243.2 million, or $1.05 per share.
FULL YEAR 2019 SUMMARY
- Total production increased 8% (14% per share) year-over-year to
101,042 BOE per day
- Liquids production increased 9% (15% per share) year-over-year
to 54,633 barrels per day
- Adjusted funds flow was $709.0
million, which exceeded capital spending of $618.9 million, generating free cash flow of
$90.1 million
- Returned $206.5 million to
shareholders through share repurchases and dividends
- Maintained strong financial flexibility; ended the year with a
net debt to adjusted funds flow ratio of 0.6 times
- Achieved 139% proved plus probable ("2P") reserves replacement,
including 206% 2P reserves replacement in North Dakota
- 2P reserves increased 3% (11% per share) year-over-year
"We delivered strong results in 2019 having generated
double-digit production per share growth and returning over
$200 million to shareholders," stated
Ian C. Dundas, President and Chief
Executive Officer. "We have positioned Enerplus to be resilient
through commodity price cycles with our strong balance sheet,
profitable growth plan underpinned by financial returns and focus
on generating free cash flow. In addition, we believe that our
commitment to environmental, social and governance initiatives will
further support long-term value creation."
FOURTH QUARTER 2019 REVIEW
Total production for the fourth quarter of 2019 was 107,436 BOE
per day, exceeding the Company's guidance range of 103,000 to
107,000 BOE per day, and a 10% increase from the same period in
2018. Crude oil and natural gas liquids production was 59,846
barrels per day in the fourth quarter, achieving the high end of
the Company's guidance range of 58,000 to 60,000 barrels per day,
and a 10% increase from the same period in 2018. The production
increase was driven by higher North
Dakota and Marcellus volumes.
Adjusted funds flow was $178.9
million in the fourth quarter, 17% lower than the same
period in 2018 primarily due to an increase in operating expenses
and a lower Alternative Minimum Tax ("AMT") refund of $13.9 million in the fourth quarter of 2019,
compared to $27.3 million in the
fourth quarter of 2018.
Enerplus recorded a net loss of $429.1
million in the fourth quarter compared to net income of
$249.3 million in the same period in
2018. Earnings decreased from the fourth quarter of 2018 primarily
due to a $451.1 million non-cash
goodwill impairment related to the Company's Canadian reporting
unit as a result of the cumulative impact of Canadian asset
divestments, the shut-in of uneconomic natural gas production in
Tommy Lakes and lower forecasted
commodity prices. Earnings were further impacted by a $28.8 million loss on commodity derivative
instruments in the fourth quarter of 2019 compared to a
$253.7 million gain in the same
period in 2018. Excluding the goodwill impairment and certain other
non-cash or non-recurring items, fourth quarter adjusted net income
was $34.4 million, compared to
$102.2 million in the same period in
2018. The reduction in adjusted net income was primarily due to
higher operating expenses and a realized foreign exchange loss in
the fourth quarter of 2019.
Enerplus' fourth quarter 2019 Bakken crude oil price
differential was US$4.40 per barrel
below WTI, compared to US$5.60 per
barrel below WTI for the same period in 2018. Enerplus' fourth
quarter Marcellus natural gas price differential was US$0.63 per Mcf below NYMEX, compared to
US$0.34 per Mcf below NYMEX for the
same period in 2018.
Operating expenses in the fourth quarter increased to
$8.05 per BOE, compared to
$6.99 per BOE in the same period in
2018, as a result of higher fluid handling costs due to increased
crude oil volumes and additional well servicing activity. Cash
general and administrative ("G&A") expenses in the fourth
quarter decreased to $1.34 per BOE,
compared to $1.40 per BOE in the same
period of 2018, primarily due to higher production.
Exploration and development capital spending totaled
$99.4 million in the fourth quarter
of 2019. The Company also spent $23.7
million repurchasing 2.7 million shares and paid
$6.7 million in dividends during the
fourth quarter.
Enerplus ended the fourth quarter of 2019 with total debt net of
cash of $455.0 million and was
undrawn on its US$600 million senior
unsecured bank credit facility. The Company's net debt to adjusted
funds flow ratio was 0.6 times at quarter-end.
FULL YEAR 2019 REVIEW
Total production for 2019 was 101,042 BOE per day, an 8% (14%
per share) increase from 2018. Crude oil and natural gas liquids
production was 54,633 barrels per day in 2019, a 9% (15% per share)
increase from 2018.
Adjusted funds flow was $709.0
million in 2019, 6% lower than 2018 primarily due to lower
benchmark commodity prices and higher operating expenses in
2019.
Enerplus recorded a net loss of $259.7
million in 2019 compared to net income of $378.3 million in 2018. Earnings decreased from
2018 primarily due to a $451.1
million non-cash Canadian goodwill impairment and a loss on
commodity derivative instruments of $66.1
million, compared to a gain of $88.2
million recorded in 2018. Excluding the goodwill impairment
and certain other non-cash or non-recurring items, 2019 adjusted
net income was $243.2 million,
compared to $344.8 million in 2018.
The reduction in adjusted net income was primarily due to lower
benchmark commodity prices and higher operating expenses in
2019.
Enerplus' 2019 Bakken crude oil price differential was
US$3.61 per barrel below WTI,
compared to US$3.78 per barrel below
WTI in 2018. Enerplus' 2019 Marcellus natural gas price
differential was US$0.39 per Mcf
below NYMEX, compared to US$0.43 per
Mcf below NYMEX in 2018.
Operating expenses in 2019 were $7.88 per BOE, compared to $7.00 per BOE in 2018. The increase was largely
due to additional well servicing activity and higher fluid handling
and gas processing costs in North
Dakota. Cash G&A expenses in 2019 were $1.32 per BOE, compared to $1.47 per BOE in 2018. The lower cash G&A
expenses per BOE were primarily due to higher production levels in
2019 compared to 2018.
Exploration and development capital spending totaled
$618.9 million in 2019, below the
Company's capital budget guidance of $625
million.
The Company spent $178.8 million
repurchasing 18.2 million shares and paid $27.7 million in dividends in 2019. Subsequent to
year end and up to February 20, 2020,
the Company repurchased 0.3 million shares for total consideration
of $2.5 million. Since initiating its
share repurchase program in the third quarter of 2018, Enerplus has
repurchased 24.5 million shares, representing approximately 10% of
shares outstanding.
2019 YEAR END RESERVES SUMMARY
- Replaced 139% of 2019 production, adding 51.0 MMBOE (57% crude
oil) of 2P reserves (including revisions and economic
factors).
- Material reserves growth was realized in North Dakota where the Company replaced 206%
of 2019 production, adding 34.2 MMBOE of 2P reserves (including
revisions and economic factors).
- Total 2P reserves were 440.8 MMBOE at year end 2019,
representing a 3% (11% per share) increase from year end 2018
- F&D costs were $15.97 per BOE
for proved developed producing ("PDP") reserves, $11.37 per BOE for proved reserves, and
$13.05 per BOE for 2P reserves,
including future development costs ("FDC").
- Finding, development and acquisition ("FD&A") costs were
$11.82 per BOE for proved reserves
and $13.63 per BOE for 2P reserves,
including FDC.
- 2P reserves were comprised of 50% crude oil, 5% natural gas
liquids, and 45% natural gas at year end 2019.
ASSET ACTIVITY
Williston Basin production
averaged 54,113 BOE per day (82% crude oil) during the fourth
quarter of 2019, 1% lower than the prior quarter and 14% higher
than the same period in 2018. Fourth quarter Williston Basin production was comprised of
50,872 BOE per day in North Dakota
and 3,241 BOE per day in Montana.
Full year 2019 production from the Williston Basin averaged 48,745 BOE per day, a
13% increase year-over-year. In the fourth quarter, the Company
drilled 12 gross operated wells (61% average working interest) in
North Dakota. No operated wells
were brought on production in the fourth quarter.
Marcellus natural gas production averaged 233 MMcf per day
during the fourth quarter of 2019, 2% higher than the prior quarter
and 10% higher than the same period in 2018. Full year 2019
production averaged 227 MMcf per day, a 9% increase year-over-year.
In the fourth quarter, the Company participated in drilling 13
gross non-operated wells (2% average working interest) with five
gross non-operated wells (28% average working interest) brought on
production.
Canadian waterflood production averaged 8,580 BOE per day (93%
crude oil) during the fourth quarter of 2019, 6% lower than the
prior quarter and 12% lower than the same period in 2018. Full year
2019 production averaged 9,083 BOE per day, an 8% decrease
year-over-year primarily due to the sale of assets in 2019 and
production declines.
Average Daily Production(1)
|
Three months
ended December 31, 2019
|
|
Twelve months
ended December 31, 2019
|
|
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
|
44.4
|
4.6
|
30.4
|
54.1
|
|
40.1
|
4.0
|
27.8
|
48.7
|
Marcellus
|
-
|
-
|
232.7
|
38.8
|
|
-
|
-
|
226.7
|
37.8
|
Canadian
Waterfloods
|
8.0
|
0.1
|
2.9
|
8.6
|
|
8.4
|
0.1
|
3.4
|
9.1
|
DJ Basin
|
1.8
|
0.1
|
0.7
|
1.9
|
|
1.0
|
0.1
|
0.2
|
1.0
|
Other(2)
|
0.1
|
0.7
|
18.8
|
4.0
|
|
0.2
|
0.8
|
20.3
|
4.4
|
Total
|
54.3
|
5.5
|
285.5
|
107.4
|
|
49.7
|
4.9
|
278.5
|
101.0
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises non-core
properties in Canada.
|
Summary of Wells Drilled(1)
|
Three months
ended December 31, 2019
|
|
Twelve months
ended December 31, 2019
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
12
|
7.3
|
|
4
|
1.0
|
|
55
|
44.6
|
|
11
|
3.7
|
Marcellus
|
-
|
-
|
|
13
|
0.3
|
|
-
|
-
|
|
38
|
1.4
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
DJ Basin
|
-
|
-
|
|
-
|
-
|
|
5
|
4.4
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
2
|
0.5
|
Total
|
12
|
7.3
|
|
17
|
1.3
|
|
61
|
50.0
|
|
51
|
5.7
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises non-core
properties in Canada.
|
Summary of Wells Brought On-Stream(1)
|
Three months
ended December 31, 2019
|
|
Twelve months
ended December 31, 2019
|
|
Operated
|
|
Non-Operated
|
|
Operated
|
|
Non-Operated
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Williston
Basin
|
-
|
-
|
|
4
|
1.6
|
|
40
|
34.3
|
|
9
|
3.6
|
Marcellus
|
-
|
-
|
|
5
|
1.4
|
|
-
|
-
|
|
45
|
5.7
|
Canadian
Waterfloods
|
-
|
-
|
|
-
|
-
|
|
1
|
1.0
|
|
-
|
-
|
DJ Basin
|
-
|
-
|
|
-
|
-
|
|
5
|
4.4
|
|
-
|
-
|
Other(2)
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
2
|
0.5
|
Total
|
-
|
-
|
|
9
|
3.0
|
|
46
|
39.7
|
|
56
|
9.8
|
(1)
|
Table may not add due
to rounding.
|
(2)
|
Comprises non-core
properties in Canada.
|
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) – GREENHOUSE GAS
EMISSIONS AND WATER TARGETS
Enerplus believes that minimizing the environmental impacts of
its operations is a foundational tenet of corporate responsibility.
Moreover, as the global economy transitions to a lower carbon
future, climate related policies and regulations around greenhouse
gas (GHG) emissions are becoming increasingly stringent, requiring
businesses to adapt to support long-term value creation. As part of
Enerplus' continued integration of ESG issues into its strategy and
operations, the Company has established targets for reducing GHG
emissions intensity and freshwater use.
Greenhouse Gas Emissions
Using 2019 as a baseline, Enerplus is targeting a 10% reduction of
its GHG emissions per barrel of oil equivalent in 2020.
Infrastructure expansion is expected to support the Company's
efforts to reduce levels of flared natural gas in North Dakota in 2020, helping it reach its GHG
emissions intensity reduction target. The Company is evaluating
additional operational changes and aims to identify technologies
and opportunities to achieve further emissions intensity reductions
beyond 2020.
Enerplus' 2020 target addresses scope 1 and 2 emissions. Scope 1
emissions are direct emissions from owned and operated facilities.
Scope 2 emissions are indirect emissions from the generation of
purchased energy for the Company's owned and operated
facilities.
Water Management
The vast majority (approximately 80% in 2018) of the water used in
Enerplus' operations is reused. As Enerplus aims to further improve
its water use efficiency, it has established a target to reduce its
freshwater use per well completion in North Dakota by 15%, on average, in 2020,
compared to 2019, by reusing produced water in its fracturing
operations.
Other ESG Focus Areas
In addition to GHG emissions and water management, Enerplus has
identified culture, stakeholder engagement, health & safety,
and board expertise & engagement as material ESG focus areas.
Enerplus believes that the continued integration of these focus
areas into its strategy and operations will enhance long-term
business resilience. Enerplus' ESG initiatives have oversight by
the Board of Directors with each material focus area mapped to the
applicable board subcommittee including the Compensation and Human
Resources Committee, the Safety and Social Responsibility Committee
and the Corporate Governance and Nominating Committee. A copy
of Enerplus' ESG presentation is available on the Company's website
at www.enerplus.com/investors/presentations-events.cfm.
BOARD CHAIR APPOINTMENT
Enerplus today announced that Elliott
Pew will be stepping down as Board Chair effective
May 7, 2020 at the Company's annual
meeting. Hilary Foulkes, a director
of Enerplus since 2014 and currently the Chair of the Corporate
Governance & Nominating Committee, has been appointed as the
new Board Chair upon Mr. Pew stepping down. Mr. Pew has served as
Board Chair since 2014 and is stepping down as part of the board's
succession planning and focus on strong continuity. Mr. Pew will
continue with Enerplus as an independent director.
"On behalf of the Board, I would like to thank Elliott for his
dedication and leadership," said Mr. Dundas. "And I look forward to
his continued contributions as a board member. I am also excited to
welcome Hilary as Chair," continued Dundas. "Her commitment and
experience during her tenure as a director have been valuable to
our company and Enerplus will continue to benefit from these
strengths in her new expanded role as Board Chair."
PRICE RISK MANAGEMENT UPDATE
Enerplus has approximately 61% of its 2020 forecasted net crude
oil production protected (based on the guidance midpoint). The
Company has used swaps, put spreads and three-way collar structures
to hedge crude oil providing downside protection, while retaining
meaningful exposure to higher crude oil prices.
Commodity Hedging Detail (As at February 20, 2020)
|
WTI Crude
Oil (US$/bbl)(1)
|
|
Jan 1 – Jan
31,
2020
|
Feb 1 – Mar
31,
2020
|
Apr 1 – Jun
30,
2020
|
Jul 1 – Sep
30,
2020
|
Oct 1 – Dec
31,
2020
|
Swaps
|
|
|
|
|
|
Volume
(bbls/d)
|
5,000
|
10,000
|
12,000
|
2,000
|
-
|
Sold Swaps
|
$57.05
|
$54.56
|
$55.23
|
$57.18
|
-
|
Put
Spreads
|
|
|
|
|
|
Volume
(bbls/d)
|
16,000
|
16,000
|
16,000
|
16,000
|
16,000
|
Sold Puts
|
$46.88
|
$46.88
|
$46.88
|
$46.88
|
$46.88
|
Purchased
Puts
|
$57.50
|
$57.50
|
$57.50
|
$57.50
|
$57.50
|
Three Way
Collars
|
|
|
|
|
|
Volume
(bbls/d)
|
-
|
-
|
-
|
5,000
|
5,000
|
Sold Puts
|
-
|
-
|
-
|
$48.00
|
$48.00
|
Purchased
Puts
|
-
|
-
|
-
|
$56.25
|
$56.25
|
Sold Calls
|
-
|
-
|
-
|
$65.00
|
$65.00
|
(1)
|
The total average
deferred premium on outstanding 2020 hedges is US$1.69/bbl from
January 1, 2020 to December 31, 2020.
|
2020 GUIDANCE
Enerplus' previously
announced and unchanged 2020 guidance is provided below.
|
|
|
Capital
spending
|
$520 to $570
million
|
Average annual
production
|
96,000 – 100,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
57,000 – 60,000
BOE/d
|
Average royalty and
production tax rate
|
26%
|
Operating
expense
|
$8.50/BOE
|
Transportation
expense
|
$4.00/BOE
|
Cash G&A
expense
|
$1.50/BOE
|
|
|
2020
Differential/Basis Outlook(1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(5.00)/bbl
|
Marcellus basis
(compared to NYMEX natural gas)
|
US$(0.45)/Mcf
|
(1) Excluding
transportation costs.
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED FINANCIAL RESULTS
|
December 31,
|
|
December 31,
|
|
2019
|
2018
|
|
2019
|
2018
|
Financial (CDN$,
thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
Net
Income/(Loss)
|
$
|
(429,143)
|
$
|
249,315
|
|
$
|
(259,720)
|
$
|
378,279
|
Adjusted Net
Income(4)
|
|
34,365
|
|
102,167
|
|
|
243,160
|
|
344,813
|
Cash Flow from
Operating Activities
|
|
188,492
|
|
221,619
|
|
|
694,240
|
|
738,784
|
Adjusted Funds
Flow(4)
|
|
178,922
|
|
214,285
|
|
|
708,992
|
|
753,506
|
Dividends to
Shareholders - Declared
|
|
6,656
|
|
7,234
|
|
|
27,688
|
|
29,256
|
Total Debt Net of
Cash(4)
|
|
454,984
|
|
333,523
|
|
|
454,984
|
|
333,523
|
Capital
Spending
|
|
99,389
|
|
72,058
|
|
|
618,910
|
|
593,876
|
Property and Land
Acquisitions
|
|
6,126
|
|
9,474
|
|
|
24,406
|
|
25,840
|
Property
Divestments
|
|
(316)
|
|
886
|
|
|
9,583
|
|
6,912
|
Net Debt to Adjusted
Funds Flow Ratio(4)
|
|
0.6x
|
|
0.4x
|
|
|
0.6x
|
|
0.4x
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) -
Basic
|
$
|
(1.93)
|
$
|
1.03
|
|
$
|
(1.12)
|
$
|
1.55
|
Net Income/(Loss) -
Diluted
|
|
(1.93)
|
|
1.02
|
|
|
(1.12)
|
|
1.53
|
Weighted Average
Number of Shares Outstanding (000's) - Basic
|
|
222,227
|
|
242,344
|
|
|
231,334
|
|
244,076
|
Weighted Average
Number of Shares Outstanding (000's) - Diluted
|
|
222,227
|
|
245,242
|
|
|
231,334
|
|
247,261
|
|
|
|
|
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
|
|
|
|
|
Oil &
Natural Gas Sales(3)
|
$
|
41.64
|
$
|
45.43
|
|
$
|
42.65
|
$
|
47.35
|
Royalties and
Production Taxes
|
|
(10.93)
|
|
(11.58)
|
|
|
(10.88)
|
|
(11.92)
|
Commodity Derivative
Instruments
|
|
0.07
|
|
(0.31)
|
|
|
0.42
|
|
(1.05)
|
Cash Operating
Expenses
|
|
(8.05)
|
|
(6.99)
|
|
|
(7.88)
|
|
(7.00)
|
Transportation
Costs
|
|
(3.82)
|
|
(3.71)
|
|
|
(3.93)
|
|
(3.63)
|
General and
Administrative Expenses
|
|
(1.34)
|
|
(1.40)
|
|
|
(1.32)
|
|
(1.47)
|
Cash Share-Based
Compensation
|
|
0.01
|
|
0.23
|
|
|
(0.02)
|
|
(0.01)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(0.89)
|
|
(0.90)
|
|
|
(0.72)
|
|
(0.92)
|
Current Income Tax
Recovery
|
|
1.41
|
|
3.03
|
|
|
0.91
|
|
0.80
|
Adjusted Funds
Flow(4)
|
$
|
18.10
|
$
|
23.80
|
|
$
|
19.23
|
$
|
22.15
|
|
Three months
ended
|
|
Twelve months ended
|
SELECTED OPERATING RESULTS
|
December 31,
|
|
December 31,
|
|
2019
|
2018
|
|
2019
|
2018
|
Average Daily
Production(2)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(bbls/day)
|
|
54,344
|
|
49,968
|
|
|
49,704
|
|
45,424
|
Natural Gas Liquids
(bbls/day)
|
|
5,502
|
|
4,483
|
|
|
4,929
|
|
4,486
|
Natural Gas
(Mcf/day)
|
|
285,537
|
|
260,453
|
|
|
278,451
|
|
259,837
|
Total
(BOE/day)
|
|
107,436
|
|
97,860
|
|
|
101,042
|
|
93,216
|
|
|
|
|
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
|
56%
|
|
56%
|
|
|
54%
|
|
54%
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
|
|
|
|
Crude Oil
(per bbl)
|
$
|
67.23
|
$
|
64.18
|
|
$
|
68.98
|
$
|
74.59
|
Natural Gas Liquids
(per bbl)
|
|
18.28
|
|
26.72
|
|
|
15.19
|
|
28.31
|
Natural Gas
(per Mcf)
|
|
2.50
|
|
4.28
|
|
|
2.87
|
|
3.42
|
|
|
|
|
|
|
|
|
|
|
Net Wells
Drilled
|
|
9
|
|
12
|
|
|
56
|
|
61
|
(1)
|
Non‑cash amounts have
been excluded.
|
(2)
|
Based on Company
interest production volumes. See "Presentation of Production and
Reserves Information" at the end of this news release.
|
(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 at the
end of this news release.
|
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 97% of the net present value (discounted at 10%,
before tax, using January 1, 2020
forecast prices and costs described below) 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 78% 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, 2020) 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 22% 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, 2020 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, 2019 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
|
6,947
|
17,046
|
60,938
|
84,930
|
8,526
|
22,808
|
617,357
|
200,150
|
Proved developed
non-producing
|
163
|
-
|
271
|
434
|
84
|
1,347
|
5,999
|
1,742
|
Proved
undeveloped
|
660
|
3,075
|
51,603
|
55,338
|
5,717
|
88
|
310,381
|
112,801
|
Total
proved
|
7,770
|
20,121
|
112,812
|
140,703
|
14,327
|
24,242
|
933,737
|
314,693
|
Total
probable
|
2,788
|
6,470
|
68,240
|
77,498
|
8,396
|
7,395
|
233,613
|
126,061
|
Proved plus
Probable
|
10,558
|
26,591
|
181,052
|
218,201
|
22,723
|
31,637
|
1,167,349
|
440,755
|
Net
|
|
|
|
|
|
|
|
|
Proved
producing
|
5,690
|
14,224
|
48,927
|
68,840
|
6,965
|
23,529
|
495,517
|
162,313
|
Proved developed
non-producing
|
138
|
-
|
221
|
359
|
62
|
1,270
|
4,808
|
1,434
|
Proved
undeveloped
|
557
|
2,558
|
41,309
|
44,424
|
4,575
|
73
|
246,155
|
90,038
|
Total
proved
|
6,385
|
16,782
|
90,457
|
113,623
|
11,602
|
24,872
|
746,480
|
253,785
|
Total
probable
|
2,160
|
5,298
|
54,576
|
62,034
|
6,758
|
7,467
|
186,702
|
101,154
|
Proved plus
Probable
|
8,545
|
22,079
|
145,033
|
175,657
|
18,361
|
32,339
|
933,182
|
354,938
|
Reserves Reconciliation
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a gross basis, from
December 31, 2018 to December 31, 2019.
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, 2018
|
9,637
|
21,181
|
106,530
|
137,347
|
13,783
|
31,007
|
849,063
|
297,809
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(982)
|
-
|
-
|
(982)
|
(18)
|
(319)
|
-
|
(1,053)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved
|
|
|
|
|
|
|
|
|
recovery
|
388
|
-
|
21,731
|
22,119
|
2,340
|
741
|
88,893
|
39,399
|
Economic
factors
|
(18)
|
(115)
|
(958)
|
(1,091)
|
(75)
|
(212)
|
(4,376)
|
(1,931)
|
Technical
revisions
|
165
|
778
|
465
|
1,408
|
46
|
1,050
|
93,164
|
17,156
|
Production
|
(1,420)
|
(1,722)
|
(14,957)
|
(18,098)
|
(1,749)
|
(8,026)
|
(93,008)
|
(36,686)
|
Proved Reserves
at
|
7,770
|
20,121
|
112,812
|
140,703
|
14,327
|
24,242
|
933,737
|
314,693
|
Dec. 31,
2019
|
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, 2018
|
3,024
|
7,215
|
60,631
|
70,869
|
7,277
|
10,129
|
300,449
|
129,909
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(232)
|
-
|
-
|
(232)
|
(9)
|
(163)
|
-
|
(268)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved
|
|
|
|
|
|
|
|
|
recovery
|
158
|
-
|
17,428
|
17,586
|
2,034
|
131
|
74,186
|
32,007
|
Economic
factors
|
3
|
7
|
(201)
|
(190)
|
(105)
|
(1,940)
|
684
|
(504)
|
Technical
revisions
|
(165)
|
(752)
|
(9,617)
|
(10,535)
|
(803)
|
(761)
|
(141,706)
|
(35,082)
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Probable Reserves
at
|
2,788
|
6,470
|
68,240
|
77,498
|
8,396
|
7,395
|
233,613
|
126,061
|
Dec. 31,
2019
|
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, 2018
|
12,660
|
28,395
|
167,160
|
208,216
|
21,060
|
41,137
|
1,149,511
|
427,718
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(1,214)
|
-
|
-
|
(1,214)
|
(27)
|
(483)
|
-
|
(1,321)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Extensions &
improved recovery
|
546
|
-
|
39,159
|
39,706
|
4,374
|
872
|
163,079
|
71,405
|
Economic
factors
|
(15)
|
(108)
|
(1,158)
|
(1,282)
|
(180)
|
(2,152)
|
(3,692)
|
(2,435)
|
Technical
revisions
|
-
|
26
|
(9,152)
|
(9,127)
|
(757)
|
289
|
(48,542)
|
(17,926)
|
Production
|
(1,420)
|
(1,722)
|
(14,957)
|
(18,098)
|
(1,749)
|
(8,026)
|
(93,008)
|
(36,686)
|
Proved Plus
Probable
Reserves at Dec. 31, 2019
|
10,558
|
26,591
|
181,052
|
218,201
|
22,723
|
31,637
|
1,167,349
|
440,755
|
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 FDC 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)
|
|
2020
|
$526
|
$550
|
2021
|
$485
|
$511
|
2022
|
$258
|
$513
|
2023
|
$31
|
$408
|
2024
|
$35
|
$72
|
2025
|
$6
|
$7
|
Remainder
|
$7
|
$5
|
Total FDC
Undiscounted
|
$1,347
|
$2,066
|
Total FDC
Discounted at 10%
|
$1,183
|
$1,723
|
F&D and
FD&A Costs – including FDC
|
|
|
|
($ millions except
for per BOE amounts)
|
2019
|
2018
|
2017
|
3
Year
|
Proved Plus
Probable Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$618.9
|
$593.8
|
$458.0
|
$1,670.7
|
Net change in Future
Development Costs
|
$47.0
|
$309.1
|
$102.8
|
$458.9
|
Gross Reserves
additions (MMBOE)
|
51.0
|
65.7
|
58.0
|
174.7
|
F&D costs
($/BOE)
|
$13.05
|
$13.74
|
$9.68
|
$12.19
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$633.7
|
$612.7
|
$415.1
|
$1,661.5
|
Net change in Future
Development Costs
|
$44.0
|
$308.1
|
$85.1
|
$437.1
|
Gross Reserves
additions (MMBOE)
|
49.7
|
64.1
|
45.6
|
159.3
|
FD&A costs
($/BOE)
|
$13.63
|
$14.37
|
$10.98
|
$13.17
|
|
|
|
|
|
Proved
Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$618.9
|
$593.8
|
$458.0
|
$1,670.7
|
Net change in Future
Development Costs
|
$2.4
|
$309.3
|
$114.0
|
$425.7
|
Gross Reserves
additions (MMBOE)
|
54.6
|
54.1
|
50.5
|
159.3
|
F&D costs
($/BOE)
|
$11.37
|
$16.69
|
$11.32
|
$13.16
|
|
|
|
|
|
Finding,
Development & Acquisition Costs
|
|
|
|
|
Capital expenditures
and net acquisitions
|
$633.7
|
$612.7
|
$415.1
|
$1,661.5
|
Net change in Future
Development Costs
|
$(0.5)
|
$308.3
|
$96.7
|
$404.5
|
Gross Reserves
additions (MMBOE)
|
53.6
|
52.9
|
41.0
|
147.5
|
FD&A costs
($/BOE)
|
$11.82
|
$17.42
|
$12.48
|
$14.01
|
|
|
|
|
|
Proved Developed
Producing Reserves
|
|
|
|
|
Finding &
Development Costs
|
|
|
|
|
Capital
Expenditures
|
$618.9
|
$593.8
|
$458.0
|
$1,670.7
|
Gross Reserves
additions (MMBOE)
|
38.8
|
45.4
|
34.8
|
118.9
|
F&D costs
($/BOE)
|
$15.97
|
$13.08
|
$13.17
|
$14.05
|
Forecast Price Assumptions
The forecast price and cost case assumes no legislative or
regulatory amendments, and includes the effects of inflation. The
estimated future net revenue to be derived from the production of
the reserves is based on the following average of the price
forecasts of McDaniel, GLJ and Sproule as of January 1, 2020 (utilized by McDaniel, NSAI and
by the Company in its internal evaluations for consistency in the
Company's reserves reporting), and the following inflation and
exchange rate assumptions.
|
WTI
Crude Oil(1) US$/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
|
|
|
|
|
|
|
|
|
2020
|
61.00
|
72.64
|
51.23
|
2.62
|
2.04
|
0.760
|
0.0
|
2021
|
63.75
|
76.06
|
56.11
|
2.87
|
2.32
|
0.770
|
1.7
|
2022
|
66.18
|
78.35
|
57.72
|
3.06
|
2.62
|
0.785
|
2.0
|
2023
|
67.91
|
80.71
|
59.45
|
3.17
|
2.71
|
0.785
|
2.0
|
2024
|
69.48
|
82.64
|
61.09
|
3.24
|
2.81
|
0.785
|
2.0
|
2025
|
71.07
|
84.60
|
62.75
|
3.32
|
2.89
|
0.785
|
2.0
|
2026
|
72.68
|
86.57
|
64.43
|
3.39
|
2.96
|
0.785
|
2.0
|
2027
|
74.24
|
88.49
|
66.04
|
3.45
|
3.03
|
0.785
|
2.0
|
2028
|
75.73
|
90.31
|
67.55
|
3.53
|
3.09
|
0.785
|
2.0
|
2029
|
77.24
|
92.17
|
69.08
|
3.60
|
3.16
|
0.785
|
2.0
|
2030
|
78.79
|
94.01
|
70.46
|
3.67
|
3.23
|
0.785
|
2.0
|
2031
|
80.36
|
95.89
|
71.87
|
3.74
|
3.29
|
0.785
|
2.0
|
2032
|
81.97
|
97.81
|
73.31
|
3.82
|
3.36
|
0.785
|
2.0
|
2033
|
83.61
|
99.76
|
74.78
|
3.89
|
3.43
|
0.785
|
2.0
|
2034
|
85.28
|
101.76
|
76.27
|
3.97
|
3.49
|
0.785
|
2.0
|
Thereafter
|
(4)
|
(4)
|
(4)
|
(4)
|
(4)
|
0.785
|
(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, 2019, ($ Millions, discounted at)
|
0%
|
5%
|
10%
|
15%
|
Proved developed
producing
|
$3,635
|
$2,835
|
$2,317
|
$1,970
|
Proved developed
non-producing
|
$27
|
$21
|
$17
|
$14
|
Proved
undeveloped
|
$1,751
|
$1,174
|
$824
|
$595
|
Total
Proved
|
$5,414
|
$4,029
|
$3,158
|
$2,579
|
Probable
|
$3,470
|
$1,902
|
$1,192
|
$815
|
Total Proved Plus
Probable Reserves (before tax)
|
$8,884
|
$5,932
|
$4,349
|
$3,394
|
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,
2019. 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, 2020, 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, 2019.
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
|
31.1
|
MMBOE
|
44.2
|
Total
Canada
|
31.1
|
MMBOE
|
44.2
|
United States
Properties
|
|
|
|
Fort Berthold –
Bakken/Three Forks Tight Oil wells
|
45.1
|
MMBOE
|
94.7
|
Marcellus - Shale
gas
|
663.5
|
Bcf
|
37.0
|
Total United
States
|
155.6
|
MMBOE
|
131.7
|
Total
Company
|
186.7
|
MMBOE
|
175.9
|
Live Conference Call
Enerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today,
February 21, 2020 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 21,
2020
|
Time:
|
9:00 am MT/11:00 am
ET
|
Dial-In:
|
416-764-8688
|
|
1-888-390-0546 (toll
free)
|
Conference
ID:
|
95232985
|
Audiocast:
|
https://event.on24.com/wcc/r/2176880/2A1E6E1D61161621B4188BA9FED0158B
|
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:
|
232985 #
|
Electronic copies of Enerplus' 2019 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
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), are Enerplus' working interest before deduction of any
royalties. Enerplus' oil and gas reserves statement for the year
ended December 31, 2019, 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, 2019 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.
All references to "liquids" in this news release include
light and medium crude oil, heavy oil and tight oil (all together
referred to as "crude oil") and natural gas liquids on a combined
basis.
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, 2020. Enerplus expects to develop
these contingent resources in the coming years however it is too
early in their development for all of these resources to be
classified as reserves at this time. A portion of these contingent
resources are part of continuous development by the Company and are
categorized as contingent resources primarily due to development
timelines that go beyond what is already assigned as undeveloped
reserves. 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, 2019. 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
2020 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 2020 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 2020, net debt to
adjusted funds-flow ratio, financial capacity and liquidity and
capital resources to fund capital spending and working capital
requirements; and our ESG initiatives, including GHG emissions
and freshwater reduction targets in 2020.
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; the
extent of our liabilities; the availability of technology and
processes to achieve environmental targets. 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' 2019 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'
2019 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation