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. For
information regarding the presentation of certain information in
this news release, see "Currency, BOE and Operational Information"
at the conclusion of this news release.
CALGARY, Dec. 17, 2014 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) has approved a capital budget
for 2015 that is designed to preserve our balance sheet strength
and financial flexibility while delivering restrained production
growth. This disciplined approach to capital spending is
focused on our core areas with the best economics.
Highlights:
- Enerplus expects to spend $635
million in capital in 2015. This represents a $195 million or 23% reduction in capital spending
compared to our 2014 forecast.
- Average 2015 production is expected to be 103,000 BOE/day to
108,000 BOE/day. At the low end of this range, Enerplus would
expect to hold production constant, and at the high end of the
range we would expect approximately 5% production growth.
- Debt-to-funds flow is expected to be below 2 times at the end
of 2015, even if WTI averages US$65/bbl for the year (NYMEX at US$3.75/MMBtu, AECO at $3.30/GJ, and FX at 1.15). We have not assumed
any proceeds from non-core divestments.
- 2015 operating costs are forecast at $10.50/BOE. This is slightly higher than 2014
estimates due to the impact of a weaker Canadian dollar when
converting our U.S. operating costs, as well as the sale of lower
operating cost non-core Canadian natural gas properties in the
fourth quarter of 2014.
- Cash general and administrative ("G&A") costs are expected
to remain constant at $2.30/BOE.
Capital Spending
Based upon the commodity price risks we see for 2015, we have
established a defensive capital budget that is designed to deliver
modest production growth and preserve our financial strength while
continuing to invest for the future. Approximately 60% of our
annual capital spending is expected to occur in the first half of
2015. We expect to drill 75 net wells and bring 80 net wells
on-stream in 2015.
|
|
2015 Capital Spending
|
$ millions
|
Development Drilling
& Completions
|
$530
|
Plant/Facilities
|
$75
|
Maintenance
|
$30
|
|
|
Total
|
$635
|
|
|
|
|
|
|
2015 Development Drilling &
Completions
|
$ millions
|
Ft. Berthold North
Dakota
|
$320
|
Canadian Crude Oil
& Waterfloods
|
85
|
|
Total crude oil
spending
|
$405
|
|
|
Marcellus
|
$90
|
Canadian Deep
Basin
|
35
|
|
Total natural gas
spending
|
$125
|
|
|
Total
|
$530
|
We expect our 2015 capital program to deliver exit capital
efficiencies of approximately $25,000
per flowing BOE per day.
North Dakota
We plan to maintain our Bakken/Three Forks two rig program in
North Dakota. We expect to invest
$320 million in Fort Berthold,
drilling approximately 24 net wells and bringing 22 net wells
on-stream. The 30-day initial production rates of our long
Bakken wells drilled in 2014 have exceeded our expectations by 20%.
These wells have one of the lowest break even supply costs within
the basin. We expect the NPV10% average break even supply
cost on our Ft. Berthold program in 2015 will be approximately WTI
US$58/bbl, which is calculated at
current costs. The majority of the capital spend is in areas
where we expect internal rates of return ("IRR") above 30% at
US$65/bbl WTI.
Canadian Crude Oil & Waterfloods
We plan to invest $135 million in
our Canadian crude oil assets in 2015 which includes $85 million of drilling and completion costs.
Approximately 45% or $60 million of
this is planned for the Brooks area in response to land retention
requirements. We expect to drill 23 wells and complete 28 wells in
Brooks in 2015. We expect a NPV10% break even supply cost of
approximately WTI US$58/bbl in
Brooks. We also expect to spend $35
million advancing our waterflood and EOR projects at
Medicine Hat and Giltedge.
Natural Gas
Spending in the Marcellus is expected to decrease by almost 45%
in 2015 to $90 million. Despite this
reduction in spending, we expect strong well performance and lower
capital costs to provide production growth of approximately 10%. We
have assumed continued Marcellus production curtailment in 2015
(similar to the curtailment experienced in 2014) in response to low
natural gas prices.
Our 2015 Canadian natural gas activities will be focused on the
Wilrich where we plan to drill two wells and complete three wells
in the Ansell area for an anticipated cost of approximately
$22 million. In the Duvernay, we plan to evaluate the performance
of our existing wells and have minimal capital spending planned for
2015.
We will continue to evaluate our capital prgoram in the context
of commodity prices, economic conditions, and cost structures and
are prepared to make changes to our overall capital spending plans
as necessary.
Production Outlook
We expect daily production will average between 103,000 BOE/day
to 108,000 BOE/day, with a relatively flat profile throughout the
year. Using the mid-point of this range, this represents a 2%
increase over our expected 2014 production levels, generally
balanced between oil/liquids and natural gas. On a per share basis,
production growth is also expected to be approximately 2%.
Expenses
Our operating costs are expected to be $10.50/BOE for 2015. This is slightly higher than
2014 due to the impact of a weaker Canadian dollar on our U.S.
operating costs, as well as the sale of lower operating cost
non-core Canadian natural gas properties during the fourth quarter
of 2014.
Cash G&A expenses are expected to be maintained at
$2.30 per BOE.
Royalty costs, including state production taxes and impact fees,
are expected to remain at 23% of revenues net of
transportation.
Based upon current commodity prices, we expect to pay cash taxes
of approximately 2% of U.S. funds flow in 2015. We have sufficient
tax pools to shelter our Canadian cash flow from material cash
taxes until after 2018.
Hedging
We have a significant amount of our crude oil volumes hedged at
prices well above the current market for the remainder of 2014 and
into 2015. For the fourth quarter of 2014, we have approximately
65% of our expected net after royalty crude oil production hedged
at a price of US$95.29 per
barrel.
In 2015, assuming the midpoint of our guidance range, we have
47% of our expected crude oil production, net of royalties, hedged
for the first six months at a WTI price of US$93.58 per barrel. We also have 24% of our
expected net crude oil production hedged for the second half of
2015 at a WTI price of US$93.86 per
barrel.
In addition to our crude oil hedges, we have downside protection
at an average NYMEX price of US$4.13/MMbtu on approximately 38% of our
forecast 2015 natural gas production after royalties, through a
combination of instruments.
Funding the 2015 Capital Program
We believe that we are well positioned to withstand the recent
commodity price volatility through a reduced capital spending
program, strong hedge position and significant credit capacity. We
expect to fund our 2015 capital program and dividend with funds
from operations and a modest increase in debt. Assuming no
additional divestments in 2015, debt-to-funds flow is expected to
be below 2 times at the end of 2015, if WTI averages US$65/bbl for the full year (NYMEX US$3.75/MMBtu, AECO at $3.30/GJ, and FX of 1.15).
At the end of December 2014, we
expect we will have approximately $925
million of credit available on our $1 billion bank facility and a trailing 12 month
debt-to-funds flow of 1.3 times. Most of our debt is in the form of
long term senior unsecured notes. We have approximately
$100 million in term debt due in the
next two years which we expect to roll into new notes or repay with
bank debt.
Dividend
The dividend is an important part of our strategy to create
shareholder value. We have no plans to change the dividend.
However, we will be monitoring commodity prices and economic
conditions going forward. We are prepared to make adjustments as
necessary to the dividend depending on the severity and duration of
the downturn.
2015 Forecast Guidance Summary
Our estimates do not include any acquisition or divestment
activities, although divestments continue to be part of our
strategy to high-grade our portfolio. Enerplus suspended its Stock
Dividend Program in September 2014 to
reduce dilution.
|
|
|
Capital
Spending
|
|
$635
million
|
Annual Average
Production
|
|
103,000 - 108,000
BOE/day
|
|
% crude oil and
natural gas liquids
|
|
43%-45%
|
Operating
Costs
|
|
$10.50/BOE
|
Cash General &
Administrative Expense
|
|
$2.30/BOE
|
Royalties (including
state fees)
|
|
23%
|
U.S. Cash
Taxes
|
|
2% of U.S. cash
flow
|
Cash
Dividends
|
|
$220
million
|
Cash Dividends per
share
|
|
$1.08
|
2015 Differential/Basis Outlook*
|
|
|
|
|
Mixed
Sweet Blend (MSW)
|
|
|
|
US($6.00)/bbl
|
Western
Canada Select (WCS)
|
|
|
|
US($17.00)/bbl
|
U.S.
Bakken
|
|
|
|
US($9.00)/bbl
|
Marcellus Basis
|
|
|
|
US($1.40)/MMBtu
|
* Before field
transportation costs. Compared to US$ WTI crude oil and US$ NYMEX
gas.
|
Electronic copies of our quarterly and annual results, news
releases and 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.
CURRENCY, BOE, 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). 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 our Canadian peer companies, the
summary results contained within this news release presents our
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.
See "Non-GAAP Measures" below.
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", "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: capital expenditures for
2015 and the timing and allocation of such expenditures among our
properties and assets; our anticipated 2014 total capital
expenditures; expected 2014 and 2015 average production volumes and
growth and the anticipated production mix; our 2014 and 2015
year-end debt-to-funds flow ratio; bank credit availability at
December 31, 2014; 2015 operating,
general and administrative and royalty costs; our anticipated U.S.
cash taxes payable in 2015, available tax shelter and the time at
which we may pay Canadian cash taxes; our anticipated 2015 drilling
program including the anticipated capital spending for such
drilling program among our properties; 2015 capital efficiencies;
our expected break even supply costs and internal rates of return
("IRR") for wells on certain of our properties; anticipated
well recovery volumes; and the proportion of our anticipated oil
and gas production that is hedged; the sources available to fund
our 2015 capital expenditures; anticipated future debt levels and
the anticipated refinancing of certain debt; our anticipated
dividend payment levels; potential acquisition and divestment
activities; future oil and natural gas prices and
differentials.
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 drilling and development plans will achieve the expected
results; 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 resource volumes; commodity price and cost
assumptions; including those set forth in this news release; the
continued availability of adequate debt and/or equity financing and
funds flow to fund our capital, operating and working capital
requirements and dividend payments as needed; the continued
availability and sufficiency of our funds flow and availability
under our bank credit facility; the availability of third party
services; and the extent of our liabilities. 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: changes
in commodity prices and deviations from anticipated commodity price
levels; changes in realized prices of Enerplus' products; changes
in the demand for or supply of our products; unanticipated
operating or drilling results, results from our capital spending
activities or production declines; 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; inaccurate
estimation of our oil and gas reserve and 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; a failure to complete planned asset dispositions
on the terms anticipated or at all; 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 our MD&A
for the year ended December 31, 2013
and in our other public filings).
The forward-looking information contained in this news
release speaks only as of the date of this news 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, we use the terms "funds flow" and
"debt-to-funds flow ratio" as measures to analyze operating
performance, leverage and liquidity. "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. "Debt-to-funds flow
ratio" is used to analyze leverage and liquidity and is calculated
as total debt net of cash, divided by a trailing 12 months of funds
flow.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "funds flow", and
"debt-to-funds flow ratio" 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. See disclosure under "Non-GAAP
Measures" in our MD&A for the three and none months ended
September 30, 2014 for reconciliation
of these measures to the most directly comparable measures
calculated in accordance with U.S. GAAP.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation