CALGARY, Jan. 17, 2012 /CNW/ - Enerplus Corporation ("Enerplus") (TSX:
ERF) (NYSE: ERF) is pleased to announce an $800 million capital
spending program for 2012 that we expect will generate significant
growth in production, reserves and cash flow.
"Over the past few years we have had tremendous success repositioning
our company and introducing significant growth opportunities to our
portfolio. Building on the success of our 2011 activities and given
the attractive opportunities available in our portfolio, we are
planning a level of spending that we expect will deliver production
growth of over 10% in 2012", says Gordon Kerr, President & Chief
Executive Officer. "We realize the dividend is important to our
investors and currently do not plan to make any changes to it. We
believe our financing plans will allow us to continue to support our
growth and income strategy while maintaining our financial flexibility
during this period of weak natural gas prices."
2012 Capital Program Highlights:
We plan to spend $800 million on exploration and development projects in
2012 with over 70% of our spending focused on oil and liquids rich
natural gas projects. Our natural gas spending is expected to be
focused primarily in the Marcellus on drilling to delineate and retain
leases. We expect to invest close to 40% of our capital in light crude
oil development at Fort Berthold, North Dakota.
We expect to deliver annual average production growth of over 10% in
2012. We are forecasting average production of approximately 83,000
BOE/day during 2012 growing to approximately 88,000 BOE/day as we exit
With the current forward commodity price outlook along with the impact
of our hedging program, we expect cash flow to increase significantly
in 2012. This increase is the result of a growth in our total
production volumes and in particular, increasing crude oil and liquids
We expect annual oil production to grow by approximately 7,000 BOE in
2012 with the majority of this growth coming from North Dakota. We
expect our average crude oil and liquids production will increase from
45% of total production in 2011 to approximately 50% in 2012.
We plan to minimize spending on our operated dry gas projects given the
current outlook for natural gas prices however we intend to continue to
invest alongside our partners in the Marcellus as they drill to
delineate and retain leases. We have allocated approximately $190
million on both our operated and non-operated leases and expect
production will grow from 25 MMcf/day currently to over 70 MMcf/day as
we exit 2012. Our Canadian conventional dry gas production is expected
to decline throughout the year while our Marcellus gas production is
expected to represent approximately 30% of our total corporate natural
gas volumes by year end.
Through a disciplined exploration program, we plan to invest close to
$100 million to unlock the value in our prospective undeveloped land
base in the Duvernay, Montney, and Cardium plays and in our operated
acreage in the Marcellus as well as advancing our enhanced oil recovery
projects. This spending is not expected to contribute significant new
production in 2012 although we expect it will set the stage for future
production and reserve additions.
The majority of our planned capital spending will be focused on our
operated properties with approximately 85% of our capital program
directed to drilling and completion activities. In total we expect to
drill approximately 108 net wells with approximately 95 net wells
coming on-stream throughout the year. Virtually all of the wells
planned in 2012 will be horizontal wells.
Based upon exit production growth, we expect to see an improvement in
capital efficiencies in the range of $30,000 - $35,000/BOE/day,
including spending on exploration activities. The low decline rate
associated with our waterflood and enhanced oil recovery projects is
helping to offset the impact of increased horizontal drilling activity
to our corporate decline rate. We expect our corporate decline rate to
increase from approximately 21% currently to 23% by year end.
Over and above our capital spending program, we plan to invest
approximately $40 million in the acquisition of new undeveloped land.
We expect to fund a portion of these expenditures through the sale of
non-core properties with limited production and have signed a sale
agreement for half of this amount.
We currently have downside protection on approximately 64% of our
anticipated net oil production (after royalty volumes) at an average
floor price of US$96.22/bbl for 2012. For calendar 2013, we currently
have 5% of our expected net oil production hedged at an effective price
of US$102.08/bbl. Given the weak outlook for natural gas prices, we
currently have no hedges in place for our natural gas production.
Despite anticipated cash flow growth in 2012 as a result of increasing
production, our capital spending program and dividends are expected to
exceed cash flow. We plan to fund the shortfall through debt and
equity financing including estimated proceeds from the Dividend
Reinvestment Program ("DRIP") program of approximately $70 million. In
addition, we continue to hold a portfolio of equity investments that we
may sell to help fund capital spending or acquisitions.
In the first half of 2012, we plan to expand our DRIP to make it
available to our U.S. investors. Approximately 65% of the total shares
currently outstanding are held by U.S. residents.
We intend to continue to distribute a meaningful portion of our cash
flow to shareholders and have no current plans to reduce our dividend
rate of $0.18/share/month. As always, we will continue to evaluate
dividend levels with respect to cash flow, debt levels, capital
spending, commodity prices and market conditions.
2012 Capital Spending Breakdown
Development Drilling & Completions
Exploration & Seismic
2012 Production Outlook
2011E vs 2012E
Crude Oil (bbls/day)
Natural Gas Liquids (bbls/day)
Natural Gas (Mcf/day)
Our Tight Oil resource play continues to be the most significant area of
investment for Enerplus attracting over 40% or $350 million of our
planned 2012 capital budget. Production is expected to grow by
approximately 30% from 17,000 BOE/day exiting 2011 to approximately
22,000 BOE/day exiting 2012.
We plan to spend the majority of our tight oil capital budget at Fort
Berthold in Dunn and McKenzie counties in North Dakota. We plan to
spend approximately $300 million drilling 27 net horizontal wells, 90%
of which will be long horizontal wells with 3 to 4 drilling rigs
working in the play during the year. Our Bakken well results have
typically outperformed our expectations throughout 2011, and as a
result, we are increasing our recovery estimates for a long Bakken
lateral well in this area to 800,000 BOE/well (previously 600,000 -
800,000 BOE/well) based upon drilling two wells per spacing unit.
Through the latter part of 2011, we experienced an escalation in our
drilling and completion costs in large part due to the high activity
levels in the region. As a result, we now expect long horizontal wells
will cost on average $10 million including drilling, completion and
tie-in. Despite this cost increase, with our increased estimate of
recoveries, we continue to see attractive rates of return in this
region of over 60% based upon current commodity prices.
Crude Oil Waterfloods
We believe our waterflood portfolio offers significant drilling,
optimization and enhanced oil recovery opportunities with attractive
economics. With a low base decline rate of approximately 12%, these
properties provide a counterbalance to our new growth properties and
help to mitigate the escalation of our overall corporate decline rate.
In 2012, we intend to invest approximately $150 million, or 46% of the
cash flow generated by these properties, to maintain production. We
plan to direct $85 million to drilling/completions/injector conversion
activities, $58 million on plant/facilities/maintenance, and $7 million
on our enhanced oil recovery projects at Giltedge and Medicine Hat.
We plan to spend approximately $190 million in the Marcellus region in
2012, with approximately 80% allocated to our partner-operated activity
in the northeast area of Pennsylvania. Despite the low natural gas
price environment, we plan to invest with our partners to retain this
valuable acreage. Well results in northeast Pennsylvania have continued
to surpass our expectations in terms of both initial production rates
and declines. Well costs in this region are currently averaging $7
million to $8 million per well. We plan to direct approximately $40
million to drilling appraisal wells on our operated leases in
Pennsylvania where we are focused on demonstrating the potential in
these areas. In total we expect to participate in drilling
approximately 20 net wells in the Marcellus with approximately 18 net
wells on-stream in 2012. Our total Marcellus production is expected to
grow from 25 MMcf/day at the end of 2011 to over 70 MMcf/day as we exit
Liquids Rich Natural Gas
As a result of drilling success in 2011, we expect to continue to invest
in liquids rich natural gas drilling in Alberta and British Columbia in
2012. We plan to spend approximately $80 million on development
drilling in the Stacked Mannville and to delineate our Montney and
Duvernay acreage positions.
We continue to have a strong balance sheet and financial flexibility.
At September 30, 2011, we had $735 million in unutilized credit
capacity on our $1 billion bank credit facility and a trailing 12-month
debt to funds flow ratio of 1.3 times.
In 2010, we voluntarily reduced our syndicated bank credit facility from
$1.4 billion to $1 billion in response to increased bank fees for
unused credit capacity. We believe we have the ability to increase
this bank facility or alternatively, to issue additional long-term debt
in the private placement market.
Royalties, Operating Costs and General & Administrative Costs
Royalties in 2012 are expected to average 21% of gross production, up
from 2011 as a result of proportionately more production from the U.S.
which has a comparatively higher royalty regime.
2012 operating costs are expected to increase to $10.40/BOE as a result
of wage escalation, rising Alberta power costs and water handling costs
in the U.S.
General and administrative costs in 2012 are expected to remain in line
with our 2011 estimates at $3.25/BOE on a cash basis and $3.55/BOE
including cash and non-cash items (mostly stock options).
We do not expect to pay material cash taxes in Canada until after 2015
as we estimate we have sufficient tax pools to offset our taxable
income prior to that time. We expect to pay U.S. cash taxes of
approximately 5% of U.S. cash flows in 2012. The U.S. taxes are
comprised mainly of Alternative Minimum Tax that can be used to offset
future taxes. These tax forecasts will be based on current commodity
prices and capital spending plans and do not take into account any
future acquisitions or divestment activities. We also have sufficient
Canadian capital loss tax pools to shelter any estimated capital gains
tax related to the sale of our equity investment portfolio.
Summary 2012 Guidance
Average annual production
Exit rate 2012 production
2012 production mix
50% oil, 50% gas
Average royalty rate
Average interest and financing costs
Marcellus carry commitment
Undeveloped land acquisitions
Gordon J. Kerr
President & Chief Executive Officer
Currency, BOE and Operational Information
All dollar amounts or references to "$" in this news release are in
Canadian dollars unless specified otherwise. Enerplus has adopted the
standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may
be misleading particularly if used in isolation. A BOE conversion ratio
of 6 Mcf:1 BOE is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. Given that the value ratio based on the
current price of crude oil as compared to natural gas is significantly
different from the energy equivalency of 6:1, utilizing a conversion on
a 6:1 basis may be misleading as an indication of value. Unless
otherwise stated, all oil and gas production information and estimates
are presented on a gross basis, before deducting royalty interests.
Cautionary Note Regarding Forward-Looking Information and Statements
This news release contains certain forward-looking information and
statements (collectively, "forward-looking information") within the
meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "budget", "guidance",
"objective", "ongoing", "may", "will", "project", "should", "believe",
"plans", "intends", "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 and statements pertaining to the following: future capital
spending amounts (including capital carry commitments), the timing and
locations of such spending and the types of projects on which such
capital will be spent; future growth in production, reserves and cash
flow and other anticipated growth opportunities; a financing strategy
to fund anticipated capital expenditures, including completion of
equity and/or debt offerings and funds raised from our DRIP (including
the future availability of our DRIP to our U.S. investors); future oil,
natural gas liquids and natural gas prices and production levels
(including anticipated 2012 average daily and exit production rates),
the product mix and sources of such production, and production decline
rates; future drilling activities and results and undeveloped land
acquisitions; future capital efficiencies, corporate netbacks and cash
flow levels; rates of return from our investments; the expected
ultimate recovery of oil or gas from a particular well; well drilling
costs, operating costs, general and administrative expenses and royalty
expenses; sales of our equity portfolio and our non-core properties and
the redeployment of proceeds realized therefrom; dividend payments made
by Enerplus and the related adjusted payout ratio; the timing and
payment of future taxes; our planned commodity risk management program;
and future liquidity, debt levels and financial capacity and
The forward-looking information contained in this news release reflect
several material factors and expectations and assumptions of Enerplus
including, without limitation: that Enerplus will achieve operational,
production and drilling results as anticipated; anticipated production
decline rates; the general continuance of current or, where applicable,
assumed industry conditions; commodity prices will remain within
Enerplus' expected range of forecast prices, being the current forward
market prices; availability of adequate cash flow, debt and/or equity
sources to fund Enerplus' capital and operating requirements as needed
and to pay dividends to shareholders as anticipated; the continuance of
existing and, in certain circumstances, proposed tax and royalty
regimes; availability of willing buyers for the investments and
properties proposed to be disposed of; that capital, operating,
financing and third party service provider costs will not exceed
Enerplus' current expectations; availability of third party service
providers (including drilling rigs and service crews) and cooperation
of industry partners; certain foreign exchange rate and other cost
assumptions; and that all conditions and approvals necessary to
complete anticipated financing activities will be satisfied or
obtained. Enerplus believes the material factors, expectations and
assumptions reflected in the forward-looking information are reasonable
at this time 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;
unanticipated operating or drilling results or production declines;
potential redeployment of available funding to alternative projects;
changes in tax or environmental laws or royalty rates; failure to
receive required regulatory or third party approvals or to satisfy
conditions required for financings; increased debt levels or debt
service requirements; insufficient available cash to pay dividends as
currently anticipated; inaccurate estimation of or changes to estimates
of Enerplus' oil and gas reserve and resource volumes and the
assumptions relating thereto; limited, unfavourable or no access to
debt or equity capital markets; increased costs and expenses; a
shortage of third party service providers; the impact of competitors;
reliance on industry partners; an inability to agree to terms with
potential buyers of investments or assets that may be disposed of; and
certain other risks detailed from time to time in Enerplus' public
disclosure documents including, without limitation, those risks
identified in our MD&A for the year ended December 31, 2010 and in
Enerplus' Annual Information Form dated March 11, 2011 for the year
ended December 31, 2010, copies of which are available on Enerplus'
SEDAR profile at www.sedar.com and which also form part of Enerplus' annual report on Form 40-F for
the year ended December 31, 2010 filed with the United States
Securities and Exchange Commission, a copy of which is available at www.sec.gov.
The forward-looking information contained in this news release speaks
only as of the date of this news release, and Enerplus assumes no
obligation to publicly update or revise such information to reflect new
events or circumstances, except as may be required pursuant to
Any financial outlook or future oriented financial information in this
news release, as defined by applicable securities legislation, has been
approved by management of Enerplus. Such financial outlook or future
oriented financial information is provided for the purpose of providing
information about management's reasonable expectations as to the
anticipated results of its proposed business activities for 2012.
Readers are cautioned that reliance on such information may not be
appropriate for other purposes.
SOURCE Enerplus Corporation
For further information:
please call 1-800-319-6462 or e-mail email@example.com.