CALGARY, Jan. 25, 2019 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) today announced
fourth quarter 2018 production at the high-end of its guidance
range, its 2019 exploration and development capital budget of
$565 to $635
million and a three-year outlook through 2021.
"We're focused on maximizing returns, driving profitable growth
and positioning our business for strong free cash flow generation,"
stated Ian C. Dundas, President and
Chief Executive Officer. "Our 2019 plan is expected to generate
double-digit returns on capital employed and competitive oil
production per share growth while operating within cash flow based
on prevailing commodity prices. Importantly, if we see commodity
prices improve, we would expect to generate meaningful free cash
flow."
Dundas continued, "We also remain committed to returning capital
to shareholders. We returned over $100
million to shareholders in 2018 through dividends and share
repurchases and we believe continuing to repurchase our shares
represents a compelling capital allocation
opportunity."
Fourth Quarter 2018 Update
- Achieved the high-end of fourth quarter and 2018 annual
production guidance
-
- Fourth quarter production of approximately 97,800 BOE per day,
including liquids of 54,400 barrels per day
- 2018 annual production of approximately 93,200 BOE per day,
including liquids of 49,900 barrels per day
- Capital spending in the fourth quarter was $72.1 million, resulting in full year 2018
capital spending of $593.9 million,
in line with the Company's guidance of $585
million
- Repurchased 5.4 million shares in the fourth quarter for
$70.5 million, bringing total
repurchases in 2018 to $79.0 million
(5.9 million shares), further enhancing per share growth and return
of capital to shareholders
Highlights of the 2019 Budget and Three-Year Outlook
- Three-year outlook through 2021 focused on maximizing financial
returns, competitive oil growth and enhancing free cash flow
generation
-
- Second-half weighted growth profile in 2019 with annual liquids
production growth of approximately 9% at the mid-point of guidance
(11% liquids production per share growth)
- Approximately 10% to 13% annual liquids production growth in
2020 and 2021
- Over the three-year period capital spending is expected to be
balanced with adjusted funds flow at US$50 per barrel WTI and US$3 per Mcf NYMEX, with free cash flow at prices
above these levels
- 2019 capital budget of $565 to
$635 million
-
- Capital spending plan based on a US$50 to US$55 per
barrel WTI oil price environment
- Capital spending and adjusted funds flow balanced at
US$50 per barrel WTI and US$3 per Mcf NYMEX with significant free cash
flow anticipated in a rising oil price environment
- 2019 production guidance of 94,000 to 100,000 BOE per day,
including 52,500 to 56,000 barrels per day of liquids
- Expect to continue repurchasing shares in 2019
- Price protection on more than 60% of 2019 forecast net oil
production, hedged largely through three-way collar structures with
average purchased put options at US$55 per barrel WTI and average upside
participation to US$65 per barrel
WTI
- Net debt to adjusted funds flow ratio expected to remain below
0.6 times in 2019 based on US$50 per
barrel WTI
2019 Operating Plan
Enerplus has allocated 80% of its 2019 capital budget to its
North Dakota development to fund a
42 net well drilling program with 30 to 38 net operated
completions.
Enerplus plans to spend 7.5% of its 2019 capital budget across
its Canadian operations. Capital activity includes drilling
approximately four net producer/injector wells, along with ongoing
polymer injection for existing projects, and facilities maintenance
and optimization.
Enerplus plans to spend 7.5% of its 2019 capital budget in the
Marcellus to drill one net well and bring five net wells on
production.
In the DJ Basin Enerplus plans to continue delineation drilling
and progressing midstream options under a measured capital program.
The Company plans to spend 5% of its 2019 capital budget in the DJ
Basin on infrastructure and to drill and complete five gross (four
net) wells.
The Company's $565 to $635 million capital budget includes an
allocation for non-drilling/completion capital, primarily related
to infrastructure in the DJ Basin, maintenance and optimization
spending, and capitalized G&A expenses. The allocation across
assets is shown in the table below.
Approximate
Capital Allocation
|
2019
Budget
|
North
Dakota
|
80.0%
|
Canada
|
7.5%
|
Marcellus
|
7.5%
|
DJ Basin
|
5.0%
|
Total
|
100%
|
2019 Guidance
The Company expects to deliver average 2019 production of
between 94,000 to 100,000 BOE per day, with crude oil and natural
gas liquids production expected to average between 52,500 to 56,000
barrels per day.
As a result of the 2018 investment profile with only modest
fourth quarter capital activity, combined with the Company's
decision to slow completions activity early in 2019 due to the
significant oil price volatility, production in the first quarter
of 2019 is expected to decline from the fourth quarter of 2018.
Following this, production is expected to meaningfully increase
with strong growth forecast for the second half of 2019.
The Company's realized Bakken crude oil price differential below
WTI is projected to be US$4.00 per
barrel in 2019. This includes the impact of Enerplus' 16,000
barrels per day of fixed physical differential sales at
approximately US$3.00 per barrel
below WTI. For the Marcellus, the Company expects robust natural
gas price realizations during the first quarter of 2019 due to the
seasonality of some of its market exposure, with realizations
moderating during the remainder of the year. Enerplus expects its
realized Marcellus natural gas price differential below NYMEX to
average US$0.30 per Mcf in 2019.
Operating expenses in 2019 are forecast to be higher than 2018
levels as a result of the higher liquids weighting in the Company's
2019 production mix, combined with increased use of electronic
submersible pumps in North Dakota.
Operating expenses are expected to average $8.00 per BOE in 2019.
Transportation expenses are expected to average $4.00 per BOE in 2019, modestly higher
year-over-year due to additional transportation commitments that
provide access to higher crude oil prices.
A summary of Enerplus' 2019 guidance is provided below.
2019
Guidance
|
Capital
spending
|
$565 to $635
million
|
Average annual
production
|
94,000 – 100,000
BOE/d
|
Average annual crude
oil and natural gas liquids production
|
52,500 – 56,000
bbl/d
|
Average royalty and
production tax rate
|
25%
|
Operating
expense
|
$8.00/BOE
|
Transportation
expense
|
$4.00/BOE
|
Cash G&A
expense
|
$1.50/BOE
|
|
|
2019
Differential/Basis Outlook(1)
|
|
U.S. Bakken crude oil
differential (compared to WTI crude oil)
|
US$(4.00)/bbl
|
Marcellus basis
(compared to NYMEX natural gas)
|
US$(0.30)/Mcf
|
(1) Excluding transportation
costs
|
Three-Year Outlook
With second-half weighted production growth in 2019, Enerplus
expects to deliver approximately 9% annual liquids production
growth at the midpoint of its guidance range. Thereafter in 2020
and 2021, Enerplus expects to grow its liquids production by 10% to
13% per year. This growth outlook is underpinned by the Company's
high-return, light oil asset in North
Dakota. Over the three-year period, capital spending is
expected to be balanced with adjusted funds flow at approximately
US$50 per barrel WTI and US$3 per Mcf NYMEX natural gas, with free cash
flow at prices above these levels.
Share Repurchase Update
During the fourth quarter of 2018, Enerplus repurchased
5,380,784 common shares under its Normal Course Issuer Bid at an
average share price of $13.10. In
total during 2018 Enerplus repurchased 5,925,084 common shares at
an average share price of $13.33 at a
cost of $79.0 million. When combined
with dividends, Enerplus returned over $100
million to shareholders in 2018.
Risk Management Update
Using swaps and collar structures, Enerplus has an average of
23,100 barrels per day of crude oil protected in 2019
(approximately 63% of net production at guidance
midpoint). Enerplus added additional natural gas hedges in
2019 and now has an average of 65,700 Mcf per day protected in 2019
(approximately 34% of net production at guidance midpoint).
Commodity Hedging Detail (As at January 24, 2019)
|
|
WTI Crude
Oil
(US$/bbl) (1)
|
Nymex Natural
Gas
(US$/Mcf) (1)
|
|
Jan 1 –
Mar 31,
2019
|
Apr 1 –
Jun 30,
2019
|
Jul 1, –
Sep 30,
2019
|
Oct 1, –
Dec 31,
2019
|
Jan 1, –
Dec 31,
2020
|
Jan 1,
–
Mar
31,
2019
|
Apr 1,
–
Oct
31,
2019
|
|
|
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
|
|
Sold Swaps
|
$53.73
|
-
|
-
|
-
|
-
|
$4.23
|
$2.85
|
Volume (bbls/d or
Mcf/d)
|
3,000
|
-
|
-
|
-
|
-
|
50,000
|
70,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
|
Sold Puts
|
$44.28
|
$44.50
|
$44.64
|
$44.64
|
$46.88
|
-
|
-
|
Volume (bbls/d or
Mcf/d)
|
17,000
|
23,500
|
24,500
|
24,500
|
16,000
|
-
|
-
|
|
|
|
|
|
|
|
|
Purchased
Puts
|
$54.12
|
$54.59
|
$54.81
|
$54.81
|
$57.50
|
$3.80
|
-
|
Volume (bbls/d or
Mcf/d)
|
17,000
|
23,500
|
24,500
|
24,500
|
16,000
|
50,000
|
-
|
|
|
|
|
|
|
|
|
Sold Calls
|
$64.12
|
$65.52
|
$65.95
|
$65.99
|
$72.50
|
$6.01
|
-
|
Volume (bbls/d or
Mcf/d)
|
17,000
|
23,500
|
24,500
|
24,500
|
16,000
|
50,000
|
-
|
(1)
|
Based on weighted
average price (before premiums).
|
(2)
|
The total average
deferred premium spent on the three-way collars is US$1.61/bbl from
January 1, 2019 to December 31, 2020.
|
Currency and Accounting Principles
All amounts in
this news release are stated in Canadian dollars unless otherwise
specified.
Barrels of Oil Equivalent
This news release also
contains references to "BOE" (barrels of oil equivalent). Enerplus
has adopted the standard of six thousand cubic feet of gas to one
barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs.
BOEs may be misleading, particularly if used in isolation. The
foregoing conversion ratios are based on an energy equivalency
conversion method primarily applicable at the burner tip and do not
represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of oil as compared to natural gas
is significantly different from the energy equivalent of 6:1,
utilizing a conversion on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S.
GAAP oil and gas sales are generally presented net of royalties and
U.S. industry protocol is to present production volumes net of
royalties. Under Canadian industry protocol oil and gas sales and
production volumes are presented on a gross basis before deduction
of royalties. In order to continue to be comparable with its
Canadian peer companies, unless otherwise stated, the information
contained within this news release presents Enerplus' production
and BOE measures on a before royalty company interest basis. All
production volumes presented herein are reported on a "company
interest" basis, before deduction of Crown and other royalties,
plus Enerplus' royalty interest. This news release also contains
references to the percentage of the Company's production that is
hedged under commodity derivatives contracts, this percentage being
based upon the Company's net of royalty production volumes.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking
information and statements ("forward-looking information") within
the meaning of applicable securities laws. The use of any of the
words "expect", "anticipate", "continue", "estimate", "guidance",
"ongoing", "may", "will", "project", "plans", "budget", "strategy"
and similar expressions are intended to identify forward-looking
information. In particular, but without limiting the foregoing,
this news release contains forward-looking information pertaining
to the following: expected 2019 average production volumes,
anticipated production growth through 2021, anticipated production
mix and Enerplus' expected source of funding thereof; the
proportion of Enerplus' anticipated oil and gas production that is
hedged; our 2019 operating plans, including the results from our
drilling program and the timing of related production; oil and
natural gas prices and differentials and our commodity risk
management programs; expected net debt to adjusted funds flow ratio
in 2019; anticipated cash G&A, operating and transportation
expenses; expected average royalty and production tax rate;
expected capital spending levels in 2019 and in the future, its
components and its impact on production; and expected share
purchases in 2019 and sources of funding thereof. The purpose of
our return on capital employed and other financial outlook
contained in this press release is 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 news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: that
Enerplus will conduct its operations and achieve results of
operations as anticipated; that Enerplus' development plans will
achieve the expected results; current commodity price and cost
assumptions; the general continuance of current or, where
applicable, assumed industry conditions; the continuation of
assumed tax, royalty and regulatory regimes; the accuracy of the
estimates of Enerplus' reserves and resources volumes; the
continued availability of adequate debt and/or equity financing,
cash flow and other sources to fund Enerplus' capital and operating
requirements, and dividend payments as needed; availability of
third party services; and the extent of its liabilities. In
addition, Enerplus' 2019 guidance contained in this news release is
based on the following: a WTI price of between US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, and a USD/CDN exchange rate of
1.32. In addition, Enerplus' three-year outlook contained in
this news release is based on the following: a WTI price of between
US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, Bakken oil price differential of
US$4.00/bbl and a Marcellus natural
gas price differential of US$0.30/Mcf. Enerplus believes the material
factors, expectations and assumptions reflected in the
forward-looking information are reasonable but no assurance can be
given that these factors, expectations, and assumptions will prove
to be correct.
The forward-looking information included in this news release
is not a guarantee of future performance and should not be unduly
relied upon. Such information involves known and unknown risks,
uncertainties and other factors that may cause actual results or
events to differ materially from those anticipated in such
forward-looking information including, without limitation: changes,
including future decline, in commodity prices; changes in realized
prices for Enerplus' products; changes in the demand for or supply
of Enerplus' products; unanticipated operating results, results
from Enerplus' capital spending activities or production declines;
curtailment of Enerplus' production due to low realized prices or
lack of adequate infrastructure; changes in tax or environmental
laws, royalty rates or other regulatory matters; changes in
development plans by Enerplus or by third party operators of
Enerplus' properties; increased debt levels or debt service
requirements; changes in estimates of Enerplus' oil and gas
reserves and resources volumes; limited, unfavourable or a lack of
access to capital markets; increased costs; a lack of adequate
insurance coverage; the impact of competitors; reliance on industry
partners; failure to complete any anticipated acquisitions or
divestitures; and certain other risks detailed from time to time in
Enerplus' public disclosure documents (including, without
limitation, those risks identified in its AIF, management's
discussion and analysis ("MD&A"), and Form 40-F at December 31, 2017).
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted funds
flow", "free cash flow" and "net debt to adjusted funds flow" 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. "Free
cash flow" is defined as "Adjusted funds flow less exploration and
development capital spending". "Net debt to adjusted funds
flow ratio" is calculated as total debt net of cash, divided by a
trailing 12 months of adjusted funds flow. Calculation of these
terms is described in Enerplus' Third Quarter 2018 MD&A under
the "Liquidity and Capital Resources" section.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "adjusted funds flow",
"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 further
information about these measures, see disclosure under "Non-GAAP
Measures" in Enerplus' Third Quarter 2018 MD&A.
Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation