CALGARY, Sept. 21 /CNW/ -- CALGARY, Sept. 21 /CNW/ - Enerplus
Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) is pleased
to announce the execution of a series of acquisitions and
divestments in support of our strategy to reposition our portfolio
and improve the focus and profitability of Enerplus. Over the past
18 months, Enerplus has added approximately 450,000 net acres of
highly prospective land in both Canada and the U.S. creating new
growth areas that are expected to add production and reserves in
the years ahead. "We have made tremendous progress on our strategy
this year", says Gordon J. Kerr, President & Chief Executive
Officer of Enerplus. "We have invested over $1.3 billion in two of
the best resource plays in North America - the Bakken light crude
oil play and the Marcellus shale gas play - expanding our portfolio
and significantly improving the future growth prospects of
Enerplus. In addition, the sale of the Kirby Oil Sands lease and
other non-core conventional assets has allowed us to keep our
balance sheet strong and will enable our people to focus on
activities that will improve our operations and the bottom line".
Acquisition of Additional Bakken Properties in North Dakota
-----------------------------------------------------------
Building on our existing Bakken land base in North Dakota, Enerplus
has entered into an agreement to acquire an additional 46,500 net
acres (72 sections) of land in the Fort Berthold area of Dunn and
McKenzie counties in North Dakota. These lands are directly
adjacent to our existing land holdings in this area and are
prospective for light crude oil in the Bakken and Three Forks
formations. The acquisition materially expands our current position
to over 70,000 net acres (109 sections) in the Fort Berthold area,
the majority of which will be operated by Enerplus with a greater
than 90% working interest. Enerplus has proven expertise in this
area and recent drilling results have been above expectations. With
this acquisition, we now have over 210,000 net acres of undeveloped
land with early stage Bakken and Three Forks potential in North
Dakota and Saskatchewan in addition to our core Bakken field at
Sleeping Giant in Montana. The acquisition includes approximately
800 bbls/day of light crude oil production and proved plus probable
reserves of 10 million BOE primarily attributable to the Bakken
formation based upon our internal evaluation. This compliments our
existing estimate of eight million BOE of unbooked proved plus
probable reserves in this area. The purchase price before closing
adjustments is US$456 million and will be funded through Enerplus'
existing credit facility. The acquisition is expected to close in
October 2010. Enerplus has been active in the Fort Berthold area
since late 2009 and over the past year we have participated in the
drilling of nine operated horizontal wells, six of which have been
completed to date. The lateral length of these wells has ranged
from 4,300 feet with 12 frac stages for the short lateral wells to
9,000 feet with 24 frac stages for the long lateral wells. 30 Day
Average 60 Day Average Production Rate/well Production Rate/well
-------------------- -------------------- Short Lateral Wells (4
wells) 800 bbls/day 650 bbls/day Long Lateral Wells (2 wells) 1,190
bbls/day 1,100 bbls/day Production from the long lateral wells has
been limited due to fluid handling capacity. Our internal
assessment of the Bakken potential in this area is approximately
five to six million barrels of original oil in place per section.
Based upon a drilling density of two wells per section (two long
lateral wells per 1,280 acres or two short lateral wells per 640
acres) with an approximate 15% recovery factor, we estimate an
additional 50 million barrels of best estimate contingent resources
on our combined working interest lands in the Fort Berthold area in
addition to the 18 million BOE of proved plus probable resevres. We
also believe the lands are prospective for the Three Forks
formation for which we have estimated four to five million barrels
of original oil in place per section. However, given the limited
production data available, we are in the process of evaluating the
potential recoveries and development opportunity that may exist in
the Three Forks. Expected Future Bakken Drilling Metrics:
---------------------------------------- Short Lateral Wells Long
Lateral Wells ------------------- ------------------ Average Length
4,300 feet 9,000 feet Number of Frac Stages 12 24 30 Day Average
Production Rates 650 bbls/day 1,200 bbls/day Expected Ultimate
Recovery/Well 300 - 400 Mbbls 600 - 800 Mbbls Costs/Well (US$) $6.0
million $8.0 million The breakeven supply cost to provide a minimum
12% rate of return in this area varies from US$40 WTI to US$60 WTI
depending upon the lateral length of wells and recovery. Using
current commodity prices and costs, we estimate the internal rates
of return on this project range from 40% to over 100%. Based upon
these economics, Enerplus will focus on maximizing the number of
long lateral length wells. Our type curve assumes that the first 30
day average initial production rate will decline by approximately
80% in the first year. Current production from our North Dakota
properties, including the recent acquisition, is approximately
3,300 bbls/day of light sweet crude excluding the associated
natural gas volumes which are not being captured at this time. We
expect production volumes to increase to over 5,000 bbls/day by
year-end. As the operator, Enerplus has the flexibility to manage
the pace of development in this region due to the long tenure of
the leases (average remaining life of 7.5 years). We expect to
increase our spending in this area by approximately $25 million on
drilling and completion activities through the remainder of 2010.
We plan to have two rigs actively working in the area. We now
estimate that our total capital expenditures in North Dakota in
2010 will be approximately $85 million. As we execute our drilling
plans over the next five years, we would expect to see production
grow to over 20,000 BOE/day from the Fort Berthold area.
Acquisition of Additional Operated Marcellus Properties
------------------------------------------------------- On August
23, 2010, Enerplus closed the acquisition of 58,500 net acres of
undeveloped land in the Marcellus shale natural gas play in
northwest West Virginia and Maryland. The acreage is predominantly
located in Preston County in West Virginia and Garret County in
Maryland creating a new, concentrated land position that Enerplus
will operate with an average 90% working interest. Enerplus has now
invested over $150 million in the Marcellus shale gas play in 2010
acquiring two key operated areas comprised of approximately 70,000
net acres in addition to the 127,000 net acres of non-operated land
that has been acquired since 2009. These new lands in West Virginia
and Maryland are in emerging areas with limited existing
development however we believe that the geologic characteristics
are similar to Fayette and Somerset counties of Pennsylvania. Early
results from offset operators including those of our joint venture
interests have been encouraging. While no proved or probable
reserves have been acquired, we estimate original gas in place on
this acreage of approximately 50 to 60 Bcf per 640 acres. The
concentrated nature of this operated position, together with the
long tenure of the leases provides Enerplus the opportunity to
control the pace of development and spending. A majority of the
leases have two to three years remaining on the original five-year
term with an additional five-year extension option at nominal cost.
Our initial plans are to shoot seismic and begin the permitting
process this fall and we expect to begin drilling in 2011. Enerplus
has captured a meaningful position in one of the best shale gas
plays in North America that we believe will provide us with
significant production growth over the next four years. To date, we
are encouraged by the results of our development plans and current
production is approximately 15 MMcf/day. We intend to continue to
manage the commodity and asset mix of our portfolio to ensure we
have flexibility in our capital spending. We are evaluating the
possibility of reducing our non-operated acreage position given the
addition of our new operated acreage and in order to maintain a
desired level of exposure. Sale of Kirby Oil Sands Lease
----------------------------- Enerplus has entered into an
agreement to sell 100% of its Kirby steam-assisted gravity drainage
oil sands lease for gross proceeds of $405 million. We acquired a
100% working interest in the Kirby lease in 2007 for $203 million
and since that time have invested an additional $58 million in
Kirby to further delineate and identify the bitumen resource on the
lease. The "best estimate" of contingent resources associated with
the lease at December 31, 2009 was 497 million barrels of bitumen.
The sale is subject to the satisfaction of customary closing
conditions and obtaining the necessary regulatory approvals and is
expected to close in early October 2010. Proceeds from the sale
will be used to retire outstanding bank debt. TD Securities Inc.
acted as exclusive advisor to Enerplus on this transaction. Upon
the conclusion of this sale, Enerplus' remaining oil sands
portfolio will consist primarily of our equity ownership of 4.3
million shares in Laricina Energy, a private in-situ oil sands
company that recently completed an equity financing at $30 per
share. Sale of Non-Core Conventional Assets
------------------------------------ Enerplus has also made further
progress on our strategy to sell non-core conventional assets in
order to improve our focus and operational efficiency. As
previously stated, we identified approximately 14,000 BOE/day of
production for sale with approximately 3,400 BOE/day sold to date.
We recently entered into agreements to sell an additional 2,500
BOE/day of production and 9.3 million BOE of proved plus probable
reserves for approximately $158.5 million. This represents sale
metrics of approximately $63,400 per flowing BOE of production and
$17.00/BOE of proved plus probable reserves including future
development costs. This production was comprised of 54% crude oil
and natural gas liquids and 46% natural gas located primarily in
British Columbia and Alberta from approximately 70 properties. The
average operating cost of these properties was over $23.00/BOE with
a netback in the range of $19.40/BOE. These sales are expected to
close on or about September 30, 2010. FirstEnergy Capital Corp. and
RBC Rundle have acted as exclusive advisors to Enerplus on these
divestment packages. We are also in the process of marketing a
third package of non-core assets. This package primarily consists
of a number of smaller non-operated properties that are gas
weighted with lower working interests. Although negotiations are
on-going, we believe we will sell a portion of these assets this
year through a series of transactions representing approximately
4,500 BOE/day of current production and realize proceeds in the
order of $140 million. Scotia Waterous Inc. is acting as exclusive
advisor to Enerplus on this divestment package. We will continue to
evaluate opportunities to improve our portfolio however we would
expect these last sales will complete the majority of our
divestment activities this year. Upon completion of these
divestments, Enerplus will have sold over 10,000 BOE/day of
non-core production in 2010 for estimated total proceeds of over
$900 million including the sale of Kirby. Impact on 2010 Production
Rates and Capital Spending
---------------------------------------------------- As a result of
these recent acquisition and divestment activities (including the
prospective third divestment package) we are adjusting our 2010
production and capital spending guidance. We now expect to exit
2010 with production in the range of 80,000 BOE/day to 82,000
BOE/day with annual average production of 83,000 BOE/day to 84,000
BOE/day depending upon the timing and execution of our development
capital plans and divestment activities. Capital spending is
expected to increase by $30 million, totaling $515 million for 2010
with expected outstanding debt at year-end of $850 million. Our
financial position remains strong providing us with the flexibility
to manage our future capital spending and acquisition plans.
Further details on our 2011 spending plans and production outlook
will be provided in our 2011 guidance release expected in
mid-December. As a result of our acquisition and divestment
activities over the past 18 months, Enerplus has significantly
changed not only the composition of our asset base, but also the
future growth potential of the company. We continue to evaluate
strategic opportunities to enhance our portfolio and intend to
maintain a disciplined approach to both our capital spending and
our balance sheet. INFORMATION REGARDING DISCLOSURE IN THIS NEWS
RELEASE All amounts in this news release are stated in Canadian
dollars unless otherwise specified. Where applicable, natural gas
has been converted to barrels of oil equivalent ("BOE") based on 6
Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion
method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in
isolation may be misleading. In accordance with Canadian practice,
production volumes and revenues are reported on a gross basis,
before deduction of Crown and other royalties, unless otherwise
stated. Unless otherwise specified, all reserves volumes in this
news release (and all information derived therefrom) are based on
"company interest reserves" using forecast prices and costs.
"Company interest reserves" consist of "gross reserves" (as defined
in National Instrument 51-101 adopted by the Canadian securities
regulators ("NI 51-101")) plus Enerplus' royalty interests in
reserves. "Company interest reserves" are not a measure defined in
NI 51-101 and do not have a standardized meaning under NI 51-101.
Accordingly, our company interest reserves may not be comparable to
reserves presented or disclosed by other issuers. This news release
also contains internal estimates of "original oil-in-place" and
"original gas-in-place". These estimates are the quantities of oil
and gas, respectively, that are estimated to exist originally in
naturally occurring accumulations and include the quantity of oil
and gas, respectively, that is estimated, as of a given date, to be
contained in known accumulations, prior to production, plus those
estimated quantities in accumulations yet to be discovered. These
estimates do not constitute recoverable volumes. There is no
certainty that all of these quantities will be discovered or, if
discovered, that it will be commercially viable to produce any
portion of these quantities. INFORMATION REGARDING CONTINGENT
RESOURCE INFORMATION IN THIS NEWS RELEASE 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
economic, 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." There is
no certainty that any portion of the volumes currently classified
as contingent resources will be produced. The contingent resource
estimates contained herein relating to the Kirby Oil Sands lease
are presented as the "best estimate" of the quantity that will
actually be recovered, effective as of December 31, 2009. Internal
contingent resource estimates relating to the Bakken properties are
effective as of August 1, 2010. 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 information relevant to the
contingent resource estimate, see the Fund's Annual Information
Form for the year ended December 31, 2009 dated March 12, 2010, a
copy of which is available on our SEDAR profile at www.sedar.com
and which forms part of our annual report on Form 40-F which is
available on EDGAR at www.sec.gov. 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
rules. In addition, under Canadian disclosure requirements and
industry practice, reserves and production are reported using gross
(or, as noted above, "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. FORWARD-LOOKING INFORMATION AND STATEMENTS This news
release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate",
"guidance", "objective", "ongoing", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are
intended to identify forward-looking information or statements. In
particular, but without limiting the foregoing, this news release
contains forward-looking information and statements pertaining to
the following: future additions to lands, production and reserves;
Enerplus' strategy and future growth potential; future production
growth; the volumes of production and potential reserves,
resources, original-oil-in-place and original gas-in-place on the
properties proposed to be acquired and sold by Enerplus; the
anticipated closing dates and purchase and sale prices of certain
oil and gas properties; potential future drilling and seismic
activities; future drilling results, costs, production rates,
break-even costs and internal rates of return; future development
of Enerplus' lands; future capital expenditures; Enerplus'
commodity and asset mix; potential asset and property dispositions
by Enerplus and the timing and proceeds that may be received in
connection therewith; Enerplus' 2010 exit production rate and
aggregate capital expenditures; and. This press release also
contains estimates of reserves, resources, original-oil-in-place
and original gas-in-place, which are by their nature estimates that
the quantities described exist in the amounts estimated. The
forward-looking information and statements contained in this news
release reflect several material factors and expectations and
assumptions of Enerplus including, without limitation: that the
properties acquired and proposed to be acquired by Enerplus will
perform as anticipated; that all conditions to closing of the
proposed acquisitions and dispositions will be satisfied or waived,
and all necessary regulatory approvals will be obtained, in a
timely manner; that buyers will be found for certain oil and gas
properties proposed to be sold by Enerplus on terms acceptable to
Enerplus; the accuracy of Enerplus' estimates of oil and gas
reserves, resources, original oil-in-place and original
gas-in-place and production potential for the properties being
acquired and disposed of; the general continuance of current or,
where applicable, assumed industry conditions and tax and
regulatory regimes; availability of cash flow, debt and/or equity
sources to fund Enerplus' capital and operating requirements as
needed; and certain commodity price and other cost assumptions.
Enerplus believes the material factors, expectations and
assumptions reflected in the forward-looking information and
statements are reasonable at this time but no assurance can be
given that these factors, expectations and assumptions will prove
to be correct. (NTD: if IRR and break-even metrics remain, this is
where all assumptions must be stated) The forward-looking
information and statements included in this news release are not
guarantees of future performance and should not be unduly relied
upon. Such information and statements involve 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 or statements including, without
limitation: the failure to complete the proposed acquisitions and
dispositions on the timing and terms currently contemplated or at
all; inaccurate estimates of oil and gas reserves, resources,
original oil-in-place, original gas-in-place, production estimates
and drilling results; changes in commodity prices; unanticipated
operating results or production declines; changes in tax or
environmental laws or royalty rates; increased debt levels or debt
service requirements; a lack of capital to conduct planned capital
expenditures, including limited, unfavourable or no access to debt
or equity capital markets; increased costs and expenses; the impact
of competitors; reliance on industry partners; and certain other
risks detailed from time to time in the Fund's public disclosure
documents including, without limitation, those risks identified in
our management's discussion and analysis for the year ended
December 31, 2009 and in the Fund's Annual Information Form for the
year ended December 31, 2009, copies of which are available on the
Fund's SEDAR profile at www.sedar.com and which also form part of
the Fund's Form 40-F for the year ended December 31, 2009, a copy
of which is available on EDGAR at www.sec.gov. The forward-looking
information and statements contained in this news release speak
only as of the date of this release and none of the Fund or its
subsidiaries assumes any obligation to publicly update or revise
them to reflect new events or circumstances, except as may be
required pursuant to applicable laws. Gordon J. Kerr President
& Chief Executive Officer Enerplus Resources Fund %CIK:
0001126874 regarding this news release, please contact our Investor
Relations department at 1-800-319-6462 or email
investorrelations@enerplus.com
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