Exhibit 99.1

 News release via Canada NewsWire, Calgary 403-269-7605

     Attention Business Editors:
     Enerplus Acquires Bakken and Marcellus assets and sells Kirby Oil Sands
     lease and other non-core assets

     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 reserves. 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

     /For further information: regarding this news release, please contact our
Investor Relations department at 1-800-319-6462 or email
investorrelations(at)enerplus.com/
     (ERF.UN. ERF)

CO:  Enerplus Resources Fund

CNW 18:22e 21-SEP-10