Exhibit 99.1

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

	    Attention Business/Financial Editors:
	    Enerplus announces results for second quarter 2009

	    <<
	    TSX: ERF.UN
	    NYSE: ERF
	    >>

	    CALGARY, Aug. 10 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to report that our operating and financial performance for the second quarter
of 2009 is on track and meeting the expectations set out at the start of 2009.
While our cash flows have been significantly impacted by the dramatic drop in
commodity prices when compared to this time last year, our production volumes,
development capital spending plans and operating and general and
administrative expenses are on target. We continue to maintain our discipline
regarding development spending and have preserved our balance sheet strength.

	    <<
	    -   Production in the quarter averaged approximately 94,500 BOE/day,
	        virtually unchanged from the first quarter of 2009 and approximately
	        6% lower than the second quarter of 2008.

	    -   Our cash flow from operations during the second quarter was $210.6
	        million, 42% lower than the second quarter of 2008.

	    -   Approximately 43% of our cash flow was distributed to our unitholders
	        during the quarter compared to 56% last year at this time as we
	        maintained monthly distributions at $0.18/unit throughout the
	        quarter. When combined with our capital spending, our adjusted payout
	        ratio was 61% for the quarter versus 80% last year. Our adjusted
	        payout ratio has averaged 83% for the first half of 2009 as we
	        continue to prudently manage our spending.

	    -   We invested approximately $36 million in our assets during the
	        quarter with year-to-date capital spending totaling approximately
	        $135 million. Year-to-date we have drilled 128 net wells with a 99%
	        success rate.

	    -   We realized cash gains of approximately $21 million on our natural
	        gas hedges and approximately $22 million on our crude oil hedges
	        during the quarter.

	    -   Based on new data obtained from our 2008 seismic program, our third
	        party independent reserve engineers have provided a new best
	        estimate of contingent resources at Kirby of approximately 507
	        million barrels, an increase of 22% over the best estimate provided
	        in 2008.

	    -   In May, we purchased a 25% working interest in 11 net sections of
	        prospective Bakken land in southeast Saskatchewan investing a total
	        of $25 million and adding approximately 200 BOE/day of non-operated
	        Bakken production to our existing tight oil portfolio.

	    -   In June, we diversified our credit sources by issuing approximately
	        $340 million in long-term debt by way of private placement in the
	        form of senior notes with terms of 6 and 12 years. The placement of
	        senior notes provides us greater flexibility in managing our long-
	        term debt portfolio at attractive rates.

	    -   Our balance sheet remains strong with a debt to trailing 12 month
	        cash flow ratio of 0.7x.

	    SELECTED FINANCIAL RESULTS

	    This news release contains certain forward-looking information and
statements. We refer you to the end of the news release under "Forward-Looking
Statements and Information" for our disclaimer on forward-looking information
and statements. For information on the use of the term "BOE" see "Information
Regarding Disclosure in this News Release" at the conclusion of this news
release. All amounts in this news release are in Canadian dollars unless
otherwise specified.

	                                Three months ended          Six months ended
	                                           June 30,                  June 30,
	    (in Canadian dollars)        2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Financial (000's)
	      Cash Flow from
	       Operating
	       Activities         $   210,608  $   364,457  $   379,996  $   620,673
	      Cash Distributions
	       to Unitholders(1)       89,610      202,346      179,147      394,704
	      Excess of Cash Flow
	       Over Cash
	       Distributions          120,998      162,111      200,849      225,969
	      Net Income/(Loss)        (3,569)     112,230       48,217      233,624
	      Debt Outstanding -
	       net of cash            713,536    1,027,578      713,536    1,027,578
	      Development Capital
	       Spending                35,562       88,008      134,805      214,270
	      Acquisitions             28,416        1,740       30,393    1,766,809
	      Divestments               1,723           86        1,736        2,208

	    Actual Cash
	     Distributions paid
	     to Unitholders       $      0.54  $      1.26  $      1.15  $      2.52

	    Financial per
	     Weighted Average
	     Trust Units(2)
	      Cash Flow from
	       Operating
	       Activities         $      1.27  $      2.22  $      2.29  $      3.98
	      Cash Distributions
	       per Unit(1)               0.54         1.26         1.08         2.52
	      Excess of Cash Flow
	       Over Cash
	       Distributions             0.73         0.99         1.21         1.45
	      Net Income/(Loss)         (0.02)        0.68         0.29         1.50
	      Payout Ratio(3)             43%          56%          47%          64%
	      Adjusted Payout Ratio(3)    61%          80%          83%          99%

	    Selected Financial
	     Results per BOE (4)
	      Oil & Gas Sales(5)  $     35.60  $     80.56  $     35.42  $     71.85
	      Royalties                 (6.28)      (15.14)       (6.36)      (13.46)
	      Commodity Derivative
	       Instruments               4.95        (7.03)        5.16        (4.35)
	      Operating Costs           (9.58)       (9.43)       (9.77)       (9.21)
	      General and
	       Administrative           (2.27)       (1.67)       (2.16)       (1.75)
	      Interest and Other
	       Income and Foreign
	       Exchange                  1.02        (1.32)        0.07        (1.10)
	      Taxes                     (0.21)       (1.78)       (0.15)       (1.49)
	      Asset Retirement
	       Obligations Settled      (0.29)       (0.52)       (0.36)       (0.51)
	    -------------------------------------------------------------------------
	    Cash Flow from Operating
	     Activities before
	     changes in non-cash
	     working capital      $     22.94  $     43.67  $     21.85  $     39.98
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    Weighted Average
	     Number of Trust
	     Units Outstanding(2)     166,264      164,483      165,807      155,984
	    Debt to Trailing
	     Twelve Month Cash
	     Flow Ratio(6)               0.7x         0.9x         0.7x        0.9x
	    -------------------------------------------------------------------------



	    SELECTED OPERATING RESULTS

	                                Three months ended          Six months ended
	                                           June 30,                  June 30,
	                                 2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Average Daily
	     Production
	      Natural gas (Mcf/day)   338,193      359,349      338,538      333,559
	      Crude oil (bbls/day)     33,715       35,486       34,075       34,376
	      Natural gas liquids
	       (bbls/day)               4,420        4,810        4,241        4,712
	      Total daily sales
	       (BOE/day)               94,501      100,188       94,739       94,681

	      % Natural gas               60%          60%          60%          59%

	    Average Selling Price (5)
	      Natural gas
	       (per Mcf)          $      3.49  $      9.87  $      4.31  $      8.79
	      Crude oil (per bbl)       59.80       114.04        51.06       100.47
	      NGLs (per bbl)            35.47        80.55        37.91        75.29
	      CDN$/US$ exchange
	       rate                      0.86         0.99         0.83         0.99

	    Net Wells drilled               5           72          128          197
	    Success Rate(7)              100%         100%          99%         100%
	    -------------------------------------------------------------------------
	    (1) Calculated based on distributions paid or payable.
	    (2) Weighted average trust units outstanding for the period, includes the
	        equivalent exchangeable partnership units.
	    (3) Payout ratio is calculated as cash distributions to unitholders
	        divided by cash flow from operating activities. Adjusted payout ratio
	        is calculated as cash distributions to unitholders plus development
	        capital and office expenditures divided by cash flow from operating
	        activities. See "Non-GAAP Measures" in the following Management's
	        Discussion and Analysis.
	    (4) Non-cash amounts have been excluded.
	    (5) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    (6) Including the trailing 12 month cash flow of Focus Energy Trust for
	        2008.
	    (7) Based on wells drilled and cased.

	    Trust Unit Trading Summary
	    For the three months ended        TSX - ERF.un             U.S.(x) - ERF
	     June 30, 2009                           (CDN$)                     (US$)
	    -------------------------------------------------------------------------
	    High                               $     27.70               $     25.13
	    Low                                $     20.42               $     16.06
	    Close                              $     25.13               $     21.49
	    -------------------------------------------------------------------------
	    (x) U.S. Composite Exchange Data including NYSE.


	    2009 Cash Distributions Per Trust Unit

	    Payment Month                             CDN$                       US$
	    -------------------------------------------------------------------------
	    First Quarter Total                $      0.61               $      0.49
	    April                              $      0.18               $      0.15
	    May                                       0.18                      0.16
	    June                                      0.18                      0.16
	    Second Quarter Total               $      0.54               $      0.47

	    Total Year-to-Date                 $      1.15               $      0.96
	    -------------------------------------------------------------------------



	    2009 PRODUCTION AND DEVELOPMENT ACTIVITY

	                                      Three months ended June 30, 2009
	                           --------------------------------------------------

	                                                            Wells Drilled
	                                                     ------------------------
	                           Production      Capital
	    Play Type                 Volumes     Spending
	                             (BOE/day) ($ millions)       Gross          Net
	    -------------------------------------------------------------------------
	    Shallow Gas                23,644  $       0.4            4            1
	    Crude Oil Waterfloods      16,158          5.2            -            -
	    Tight Gas                  16,371          6.2            -            -
	    Bakken/Tight Oil           10,477          6.4            1            -
	    Conventional Oil & Gas     27,851         12.5            6            4
	    -------------------------------------------------------------------------
	    Total Conventional         94,501         30.7           11            5

	    Oil Sands                       -          4.9            -            -
	    -------------------------------------------------------------------------
	    Total                      94,501  $      35.6           11            5
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	                                        Six months ended June 30, 2009
	                            -------------------------------------------------

	                                                             Wells Drilled
	                                                      -----------------------
	                           Production      Capital
	    Play Type                 Volumes     Spending
	                             (BOE/day) ($ millions)       Gross          Net
	    -------------------------------------------------------------------------
	    Shallow Gas                24,026  $      29.6          121          105
	    Crude Oil Waterfloods      16,162         13.5            2            1
	    Tight Gas                  15,882         35.3           20           11
	    Bakken/Tight Oil           10,644         17.5            2            1
	    Conventional Oil & Gas     28,025         25.7           36           10
	    -------------------------------------------------------------------------
	    Total Conventional         94,739        121.6          181          128
	    Oil Sands                       -         13.2            -            -
	    -------------------------------------------------------------------------
	    Total                      94,739  $     134.8          181          128
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    >>


	    Our development capital program for the quarter was significantly lower
than the first quarter due to weakening gas prices, traditionally slower
activity due to winter break-up and the conservative approach we have taken on
our spending to preserve our balance sheet. Approximately $36 million was
invested during the quarter with year-to-date capital spending totaling
approximately $135 million. Our shallow gas activities have been concentrated
at Shackleton, Bantry and Verger with 105 net infill wells drilled
year-to-date. Tight gas activity has centred at Tommy Lakes with the
completion of a successful 14 well program earlier this year, including the
first horizontal well drilled on our lands. The horizontal well is producing
as expected with initial production rates of approximately 4 MMcf/day and
reserve estimates of approximately 3.5 Bcf, roughly three times that of a
vertical well. Our tight oil development activities have been focused
primarily at Sleeping Giant where we had a drilling program early in the year
and continued an active refrac program. The remainder of our development
spending has been on production optimization in various fields within our
waterflood resource play and our conventional oil and gas assets.
	    For the remainder of the year, our development capital spending will
focus on crude oil projects, royalty incentive supported natural gas drilling
in Alberta and new growth projects. Our crude oil program is planned to target
the expansion of the refrac program at Sleeping Giant as well as a possible
resumption of our drilling program in this area later this year. We plan to
initiate a small drilling program in Manitoba and southeast Saskatchewan and
expect to continue optimization projects across a variety of crude oil
properties. We also plan to leverage off of the Drilling Royalty Credit
program implemented by the Alberta government to support our natural gas
drilling efforts in Alberta. We have suspended further drilling in Shackleton
due to the weak natural gas price environment and will continue to monitor gas
prices to determine if this program will be resumed later this year. In spite
of the weakness in natural gas prices we shut in only a limited amount of
natural gas production (less than 250 BOE/day) during the quarter. We do not
currently anticipate any additional shut-ins however we will continue to
evaluate the economics of all our production and will make further decisions
as warranted.
	    Our growth activities are focused in the tight gas and Bakken/tight oil
resource plays. We have acquired modest land positions in both the Montney
region in British Columbia and Alberta and the Nordegg region in Alberta, and
we have recently completed an agreement for the joint development of our
interests in the Nordegg with another industry partner. Both of these growth
plays are in the early stages and we plan to continue to build positions and
evaluate opportunities going forward. We also plan to drill initial wells on
our southeast Saskatchewan Bakken lands acquired in 2008. We continue to
expect to spend $300 million on our overall development capital in 2009
however we will continue to review our spending plans in relation to commodity
prices.

	    ACQUISITION ACTIVITY

	    We continue to evaluate acquisition opportunities that will add
meaningful growth in reserves and production, focusing primarily on tight gas
opportunities in British Columbia and Alberta, tight oil opportunities in
Saskatchewan and North Dakota, as well as shale gas opportunities in the
United States. In May, we purchased a 25% working interest in 11 net sections
of prospective Bakken land in southeast Saskatchewan and entered into a
material area of mutual interest agreement with an industry partner, investing
a total of $25 million. This acquisition has added approximately 200 BOE/day
of non-operated Bakken production to our existing tight oil portfolio and we
plan to participate in the drilling of 7 gross wells during the remainder of
2009 spending approximately $5 million. This acquisition builds on our
existing portfolio of Bakken prospects in Saskatchewan and Montana and will
provide future growth potential in this tight oil resource play.

	    UPDATED RESOURCE ESTIMATE AT KIRBY OIL SANDS LEASE

	    In April, we announced the deferral of our Kirby oil sands project due to
inflated cost structures and a weak commodity price environment. Despite the
deferral, we reiterated our plans to complete the regulatory application for
the initial 10,000 bbl/day commercial project and to obtain an updated
resource estimate. The regulatory application for the first phase of the
project continues to move forward and we expect to receive regulatory approval
early in 2010. We have also updated our resource estimate based on new data
obtained from our 2008 seismic program. Our third party independent reserve
engineers have provided an updated best estimate of contingent resources of
approximately 507 million barrels, an increase of 22% from the 414 million
barrel best estimate provided in 2008 and 108% higher than the original
independent best estimate assessed when we purchased the Kirby lease in 2007.
We believe there is further opportunity to increase the resource estimate at
Kirby and long-term value in the project. We will continue to monitor
economic, regulatory and technical developments should we revisit our plans
for Kirby at a later date. For additional information on contingent resource
estimates, see "Information Regarding Contingent Resource Estimates" at the
end of the Management's Discussion and Analysis section of this news release.

	    CORPORATE CONVERSION UPDATE

	    As the implementation of the SIFT tax effective January 1, 2011
approaches, we continue to develop plans for the conversion to a corporation
by late 2010. We remain committed to our business strategy of paying a
significant portion of our cash flow directly to our investors regardless of
our legal structure. The conversion to a corporation would be a change to our
legal structure only and not a change to our fundamental business model of
being a distribution-oriented entity in the oil and gas industry. A conversion
proposal would be subject first to Board approval and a subsequent vote by
unitholders for acceptance.

	    STRATEGIC FOCUS

	    We remain committed to managing our business prudently throughout these
challenging economic times. Our strong financial position and acquisition
experience has positioned us to take advantage of strategic asset
opportunities both in Canada and the United States that will help to evolve
and improve our organization. We are keenly focused on reducing costs and
increasing efficiencies on our existing asset base through disciplined
spending of our development capital while preserving our drilling inventory
for periods of higher prices with better economic returns. We are also in the
process of identifying existing assets that may not be core to our long-term
business strategy for disposition at a later time. We believe there is an
opportunity to improve our business during this period of economic recovery
that will position us strongly for the future.

	    MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

	    The following discussion and analysis of financial results is dated
August 6, 2009 and is to be read in conjunction with:

	    <<
	    -   the audited consolidated financial statements as at and for the years
	        ended December 31, 2008 and 2007 and accompanying management's
	        discussion and analysis; and
	    -   the unaudited interim consolidated financial statements as at and for
	        the three and six months ended June 30, 2009 and 2008.
	    >>

	    All amounts are stated in Canadian dollars unless otherwise specified.
All references to GAAP refer to Canadian generally accepted accounting
principles. All note references relate to the notes included with the
accompanying unaudited interim consolidated financial statements. In
accordance with Canadian practice revenues are reported on a gross basis,
before deduction of Crown and other royalties, unless otherwise stated. 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.
	    The following MD&A contains forward-looking information and statements.
We refer you to the end of this news release under "Forward-Looking
Information and Statements" for our disclaimer on forward-looking information
and statements.

	    NON-GAAP MEASURES

	    Throughout the MD&A we use the term "payout ratio" and "adjusted payout
ratio" to analyze operating performance, leverage and liquidity. We calculate
payout ratio by dividing cash distributions to unitholders ("cash
distributions") by cash flow from operating activities ("cash flow"), both of
which appear on our consolidated statements of cash flows. "Adjusted payout
ratio" is calculated as cash distributions plus development capital and office
expenditures divided by cash flow. The terms "payout ratio" and "adjusted
payout ratio" do not have a standardized meaning or definition as prescribed
by GAAP and therefore may not be comparable with the calculation of similar
measures by other entities. Refer to the Liquidity and Capital Resources
section of the MD&A for further information.

	    OVERVIEW

	    Our second quarter operating results were on target with expectations as
production averaged 94,501 BOE/day, operating costs were $9.93/BOE and general
and administrative costs were $2.49/BOE. Development capital spending slowed
to $35.6 million reflecting our conservative approach in the current commodity
price environment. We are continuing to closely evaluate our capital projects
and will adjust our spending accordingly should commodity price levels change
significantly.
	    The decrease in commodity price levels has directly impacted our cash
flow and earnings. Our cash flow totaled $210.6 million for the quarter, a 42%
decrease from $364.5 million in the second quarter of 2008. We also had a $3.6
million net loss during the quarter compared to net income of $112.2 million
in 2008. Our payout ratio and adjusted payout ratio for the quarter was 43%
and 61% respectively, reflecting our reduced distribution levels and decreased
capital spending.
	    During the quarter we successfully closed an offering of senior unsecured
notes by way of private placement and raised gross proceeds of approximately
$338.7 million that were used to pay down bank indebtedness. We continue to
have significant financial flexibility to pursue acquisition opportunities
with over $1.3 billion of available credit capacity on our syndicated bank
facility and a debt to trailing twelve month cash flow ratio of 0.7x.

	    RESULTS OF OPERATIONS

	    Production

	    Production in the second quarter of 2009 averaged 94,501 BOE/day, in-line
with our expectations but slightly below 2009 first quarter production of
94,962 BOE/day and 6% lower than production of 100,188 BOE/day in the second
quarter of 2008. The 6% decrease from 2008 is primarily due to natural
production declines.
	    Average production volumes for the three and six months ended June 30,
2009 and 2008 are outlined below:

	    <<
	                     Three months ended June 30,    Six months ended June 30,
	    Daily Production                          %                            %
	     Volumes             2009     2008   Change     2009       2008   Change
	    -------------------------------------------------------------------------
	    Natural gas
	     (Mcf/day)        338,193  359,349     (6)%  338,538    333,559       1%
	    Crude oil
	     (bbls/day)        33,715   35,486     (5)%   34,075     34,376     (1)%
	    Natural gas
	     liquids
	     (bbls/day)         4,420    4,810     (8)%    4,241      4,712    (10)%
	    Total daily
	     sales (BOE/day)   94,501  100,188     (6)%   94,739     94,681       -%
	    -------------------------------------------------------------------------
	    >>

	    We are expecting lower production levels during the second half of 2009
due to planned facility turnarounds, a reduction in capital spending and
declines from flush production associated with our winter drilling program. We
currently have a modest amount of natural gas production shut in due to
pricing and are not expecting a significant amount of additional curtailment
as the majority of our wells are covering their variable costs at current
prices. We continue to expect 2009 annual production volumes to average 91,000
BOE/day and our 2009 exit rate to be approximately 88,000 BOE/day.

	    Pricing

	    The prices received for our natural gas and crude oil production have a
direct impact on our earnings, cash flow and financial condition. The
following table compares our average selling prices and benchmark price
indices for the three and six months ended June 30, 2009 and 2008.

	    <<
	                     Three months ended June 30,    Six months ended June 30,
	    Average Selling                           %                            %
	     Price(1)            2009     2008   Change     2009       2008   Change
	    -------------------------------------------------------------------------
	    Natural gas
	     (per Mcf)        $  3.49  $  9.87    (65)%  $  4.31   $   8.79    (51)%
	    Crude oil
	     (per bbl)        $ 59.80  $114.04    (48)%  $ 51.06   $ 100.47    (49)%
	    Natural gas
	     liquids
	     (per bbl)        $ 35.47  $ 80.55    (56)%  $ 37.91   $  75.29    (50)%
	    Per BOE           $ 35.60  $ 80.56    (56)%  $ 35.42   $  71.85    (51)%

	    Average Benchmark
	     Pricing
	    -------------------------------------------------------------------------
	    AECO natural gas -
	     monthly index
	     (CDN$/Mcf)       $  3.66  $  9.35    (61)%  $  4.65   $   8.24    (44)%
	    AECO natural gas -
	     daily index
	     (CDN$/Mcf)       $  3.45  $ 10.22    (66)%  $  4.18   $   9.06    (54)%
	    NYMEX natural gas -
	     monthly NX3 index
	     (US$/Mcf)        $  3.60  $ 10.80    (67)%  $  4.19   $   9.43    (56)%
	    NYMEX natural gas -
	     monthly NX3 index
	     CDN$ equivalent
	     (CDN$/Mcf)       $  4.19  $ 10.91    (62)%  $  5.05   $   9.53    (47)%

	    WTI crude oil
	     (US$/bbl)        $ 59.62  $123.98    (52)%  $ 51.35   $ 110.95    (54)%
	    WTI crude oil
	     CDN$ equivalent
	     (CDN$/bbl)       $ 69.33  $125.23    (45)%  $ 61.87   $ 112.07    (45)%
	    CDN$/US$ exchange
	     rate                0.86     0.99    (13)%     0.83       0.99    (16)%
	    -------------------------------------------------------------------------
	    (1) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    >>

	    During the quarter the average of the AECO monthly and daily gas price
declined 33% from $5.28/Mcf in the first quarter to $3.56/Mcf in the second
quarter. The decrease was a continuation of the price erosion seen earlier in
the year as weak demand and strong North American supply continued to push gas
prices down. Seasonally high gas storage inventories combined with a lack of
warm weather, which usually drives up the demand for cooling related, gas
fired electricity generation, have put downward pressure on gas prices.
	    We realized an average price on our natural gas of $3.49/Mcf (net of
transportation costs) during the second quarter of 2009, a decrease of 65%
from $9.87/Mcf for the same period in 2008. For the six months ended June 30,
2009 we realized an average price of $4.31/Mcf, a 51% decrease from the same
period in 2008. The majority of our natural gas sales are priced with
reference to the average of the monthly and daily AECO indices. The index
decreases for the three and six months ended June 30, 2009 are comparable to
the changes experienced in our realized prices at AECO.
	    The price of crude oil increased quarter over quarter with the average
West Texas Intermediate ("WTI") price increasing 38% from US$43.08/bbl in the
first quarter of 2009 to US$59.62/bbl in the second quarter of 2009. However,
in comparison to last year, crude oil prices remained depressed during the
quarter mainly as a result of high inventories and declining demand with WTI
averaging US$59.62/bbl, a 52% decrease compared to US$123.98/bbl for the same
period in 2008. In Canadian dollars WTI decreased 45% to $69.33/bbl from
$125.23/bbl for the same period in 2008. Enerplus' average realized crude oil
sales price was $59.80/bbl (net of transportation costs) for the second
quarter, a 48% decrease from $114.04/bbl during the same period in 2008. For
the six months ended June 30, 2009 our realized crude oil sales prices was
$51.06/bbl (net of transportation costs), a 49% decrease from $100.47/bbl
during the same period in 2008. The decrease in our realized prices for the
three and six months ended June 30, 2009 are comparable to the changes
experienced with the benchmark price for crude oil.
	    The Canadian dollar weakened against the U.S. dollar during the three and
six months ended June 30, 2009 compared to the same periods in 2008. As most
of our crude oil and natural gas is priced in reference to U.S. dollar
denominated benchmarks, this movement in the exchange rate increased the
Canadian dollar prices that we would have otherwise realized.

	    Price Risk Management

	    We continue to adjust our price risk management program with
consideration given to our overall financial position together with the
economics of our development capital program and potential acquisitions.
Consideration is also given to the upfront and potential costs of our risk
management program as we seek to limit our exposure to price downturns. Hedge
positions for any given term are transacted across a range of prices and
periods.
	    Given the above framework and objectives, we have entered into additional
commodity contracts during and subsequent to the second quarter of 2009.
Considering all financial contracts transacted as of July 29, 2009, we have
protected a portion of our natural gas sales through October 2010 and a
portion of our crude oil sales through December 2010. We have also hedged a
portion of our electricity consumption through December 2011 to protect
against rising electricity costs in the Alberta power market. See Note 8 for a
detailed list of our current price risk management positions.
	    The following is a summary of the financial contracts in place at July
29, 2009 expressed as a percentage of our anticipated production volumes net
of royalties:


	    <<
	                             Natural Gas                      Crude Oil
	                              (CDN$/Mcf)                      (US$/bbl)
	                 ------------------------------------   ---------------------
	                      July 1, November 1,    April 1,     July 1,  January 1,
	                      2009 -     2009  -      2010 -      2009 -      2010 -
	                  October 31,   March 31, October 31,   December,   December
	                        2009        2010        2010     31 2009    31, 2010
	    -------------------------------------------------------------------------
	    Purchased Puts
	     (floor prices)  $  8.30     $  8.99     $     -     $ 98.08     $     -
	      %                  18%          9%          -%         25%          -%

	    Sold Puts
	     (limiting
	     downside
	     protection)     $  7.85     $     -     $     -     $ 66.17     $ 47.50
	      %                   4%          -%          -%         11%         10%

	    Swaps
	    (fixed price)    $  7.41     $  7.33     $  7.33     $100.05     $ 74.78
	      %                  11%         10%         10%          2%         23%

	    Sold Calls
	     (capped price)  $     -     $ 12.13     $     -     $ 92.98     $     -
	      %                   -%          2%          -%         11%          -%

	    Bought Calls
	     (increasing
	     upside
	     participation)  $     -     $     -     $     -     $     -     $ 93.06
	      %                   -%          -%          -%          -%         17%
	    -------------------------------------------------------------------------
	    Based on weighted average price (before premiums), estimated average
	    annual production of 91,000 BOE/day, net of royalties and assuming an 18%
	    royalty rate.
	    >>

	    Accounting for Price Risk Management

	    During the second quarter of 2009 our price risk management program
generated cash gains of $20.6 million on our natural gas contracts and $22.0
million on our crude oil contracts. In comparison, during the second quarter
of 2008 we experienced cash losses of $16.0 million and $48.0 million
respectively. For the six months ended June 30, 2009 we experienced cash gains
of $34.9 million on our natural gas contracts and $53.6 million on our crude
oil contracts, compared to cash losses of $11.8 million and $63.2 million
respectively, for the same period in 2008. The cash gains in 2009 are a result
of commodity floor protection which helped to offset the drop in commodity
prices.
	    At June 30, 2009 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represented gains of $47.6 million
and $36.1 million respectively. These gains are recorded as current deferred
financial assets on our balance sheet. In comparison, at March 31, 2009 the
fair value of our natural gas and crude oil derivative instruments represented
gains of $57.3 million and $76.3 million respectively. As the forward markets
for natural gas and crude oil fluctuate, new contracts are executed and
existing contracts are realized, changes in fair value are reflected as a
non-cash charge or a non-cash gain to earnings. The change in the fair value
of our commodity derivative instruments between the first and second quarter
of 2009 resulted in unrealized losses of $9.7 million for natural gas and
$40.2 million for crude oil. For the six months ended June 30, 2009 the change
in fair value of our commodity derivative instruments resulted in an
unrealized gain of $23.3 million for natural gas and an unrealized loss of
$60.5 million for crude oil. See Note 8 for details.

	    The following table summarizes the effects of our financial contracts on
income:

	    <<
	    Risk Management Costs    Three months ended       Three months ended
	    ($ millions, except            June 30,                 June 30,
	    per unit amounts)               2009                      2008
	    -------------------------------------------------------------------------
	    Cash gains/(losses):
	      Natural gas         $    20.6   $   0.67/Mcf  $   (16.0)  $ (0.49)/Mcf
	      Crude oil                22.0   $   7.16/bbl      (48.0)  $(14.86)/bbl
	                          ----------                ----------
	    Total Cash
	     gains/(losses)       $    42.6   $   4.95/BOE  $   (64.0)  $ (7.03)/BOE

	    Non-cash losses on
	     financial contracts:
	      Change in fair value
	       - natural gas      $    (9.7)  $ (0.31)/Mcf  $   (39.7)  $ (1.21)/Mcf
	      Change in fair value
	       - crude oil            (40.2)  $(13.11)/bbl     (121.3)  $(37.56)/bbl
	                          ----------                ----------
	    Total non-cash losses $   (49.9)  $ (5.80)/BOE  $  (161.0)  $(17.65)/BOE

	                          ----------                ----------
	    Total losses          $    (7.3)  $ (0.85)/BOE  $  (225.0)  $(24.68)/BOE
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    Risk Management Costs     Six months ended         Six months ended
	    ($ millions, except            June 30,                 June 30,
	    per unit amounts)               2009                      2008
	    -------------------------------------------------------------------------
	    Cash gains/(losses):
	      Natural gas         $    34.9   $   0.57/Mcf  $   (11.8)  $ (0.19)/Mcf
	      Crude oil                53.6   $   8.69/bbl      (63.2)  $(10.10)/bbl
	                          ----------                ----------
	    Total Cash
	     gains/(losses)       $    88.5   $   5.16/BOE  $   (75.0)  $ (4.35)/BOE

	    Non-cash gains/(losses)
	     on financial contracts:
	      Change in fair value
	       - natural gas      $    23.3   $   0.38/Mcf  $   (98.0)  $ (1.61)/Mcf
	      Change in fair value
	       - crude oil            (60.5)  $ (9.82)/bbl     (142.4)  $(22.77)/bbl
	                          ----------                ----------
	    Total non-cash losses $   (37.2)  $ (2.17)/BOE  $  (240.4)  $(13.95)/BOE

	                          ----------                ----------
	    Total gains/(losses)  $    51.3   $   2.99/BOE  $  (315.4)  $(18.30)/BOE
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    >>

	    Revenues

	    Crude oil and natural gas revenues were marginally higher during the
second quarter of 2009 compared to the first quarter of 2009 as the impact of
increased oil prices was generally offset by lower natural gas prices and a
slight decrease in production.
	    Crude oil and natural gas revenues for the three months ended June 30,
2009 were $306.2 million ($312.5 million, net of $6.3 million transportation
costs) compared to $734.4 million ($741.5 million, net of $7.1 million
transportation costs) for the same period in 2008. For the six months ended
June 30, 2009 revenues were $607.4 million ($620.1 million, net of $12.7
million transportation costs) compared to $1,238.1 million ($1,251.5 million,
net of $13.4 million transportation costs) during the same period in 2008. The
majority of the decrease in revenues in 2009 was due to the significant
decline in commodity prices.

	    The following table summarizes the changes in sales revenue:

	    <<
	    Analysis of Sales
	    Revenue (1)
	    ($ millions)            Crude Oil         NGLs  Natural Gas        Total
	    -------------------------------------------------------------------------
	    Quarter ended June 30,
	      2008                $     368.3  $      35.4  $     330.7  $     734.4
	    Price variance(1)          (166.4)       (18.2)      (203.3)      (387.9)
	    Volume variance             (18.4)        (2.9)       (19.0)       (40.3)
	    -------------------------------------------------------------------------
	    Quarter ended June 30,
	     2009                 $     183.5  $      14.3  $     108.4  $     306.2
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    -------------------------------------------------------------------------
	    ($ millions)            Crude Oil         NGLs  Natural Gas        Total
	    -------------------------------------------------------------------------

	    Year-to-date June 30,
	     2008                 $     628.6  $      64.6  $     544.9  $   1,238.1
	    Price variance(1)          (304.9)       (28.7)      (286.5)      (620.1)
	    Volume variance              (8.8)        (6.8)         5.0        (10.6)
	    -------------------------------------------------------------------------
	    Year-to-date June 30,
	     2009                 $     314.9  $      29.1  $     263.4  $     607.4
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (1) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    >>

	    Royalties

	    Royalties are paid to various government entities and other land and
mineral rights owners. On January 1, 2009 a new royalty regime came into
effect in the province of Alberta where approximately 60% of our production is
located. This new regime has provisions for escalating royalty rates depending
on production and price levels. For the three and six months ended June 30,
2009 royalties were $54.0 million and $109.0 million respectively, both
approximately 18% of oil and gas sales net of transportation costs. In the
comparable periods of 2008, royalties were $138.0 million and $231.9 million
respectively, both approximately 19% of oil and gas sales net of
transportation costs. The decrease in royalties is attributable to lower
commodity prices.
	    On March 3, 2009, the Alberta government announced a Drilling Royalty
Credit program designed to stimulate drilling activity in the province by
offering a credit of $200 per metre drilled. To date we have not recorded any
benefits under the program but are currently reviewing the program details for
incorporation into our capital spending plans, particularly on our shallow gas
projects which we would otherwise defer under current economic conditions.

	    Operating Expenses

	    Operating expenses during the second quarter of 2009 increased to
$9.93/BOE from $9.84/BOE in the first quarter of 2009, primarily due to
non-cash losses on our power hedging of $3.0 million or $0.35/BOE.
	    For the second quarter of 2009 operating expenses were $85.4 million or
$9.93/BOE compared to $86.0 million or $9.43/BOE for the second quarter of
2008. For the six months ended June 30, 2009 operating expenses were $169.5
million or $9.89/BOE compared to $158.0 million or $9.17/BOE for the same
period in 2008. Operating expenses for 2009 were in-line with our expectations
and higher than 2008 mainly due to power hedging losses and increased spending
on regulatory requirements and well maintenance.
	    We are monitoring our operations to prudently reduce costs where
possible, however we expect costs to increase on a $/BOE basis during the
remainder of the year due to planned turnarounds and the anticipated decline
in production. We are maintaining our annual guidance for operating costs of
approximately $10.65/BOE.

	    General and Administrative Expenses ("G&A")

	    During the second quarter of 2009 G&A expenses increased 13% per BOE to
$2.49/BOE compared to $2.21/BOE for the first quarter of 2009, largely due to
transaction costs of $2.3 million related to the new senior notes offering.
Excluding these transaction costs G&A would have otherwise been $2.23/BOE for
the second quarter.
	    G&A expenses for the three months ended June 30, 2009 were $21.4 million
or $2.49/BOE compared to $17.3 million or $1.90/BOE for the second quarter of
2008. G&A expenses totaled $40.3 million or $2.35/BOE for the six months ended
June 30, 2009 compared to $33.8 million or $1.96/BOE for the same period in
2008. The increase was due to transaction costs related to the new senior
notes offering and the impact of lower overhead recoveries resulting from a
reduced capital program.
	    Non-cash G&A charges have remained relatively flat year-over-year. For
the three and six months ended June 30, 2009 our G&A expenses included
non-cash charges of $1.9 million or $0.22/BOE and $3.3 million or $0.19/BOE
respectively, compared to $2.1 million or $0.23/BOE and $3.6 million or
$0.21/BOE for the same periods in 2008. These amounts relate solely to our
trust unit rights incentive plan and are determined using a binomial lattice
option-pricing model. See Note 7 for further details.

	    The following table summarizes the cash and non-cash expenses recorded in
G&A:

	    <<
	    General and
	    Administrative
	    Costs               Three months ended June 30, Six months ended June 30,
	    ($ millions)                 2009         2008         2009         2008
	    -------------------------------------------------------------------------

	    Cash                  $      19.5  $      15.2  $      37.0  $      30.2
	    Trust unit rights
	     incentive plan
	     (non-cash)                   1.9          2.1          3.3          3.6
	    -------------------------------------------------------------------------
	    Total G&A             $      21.4  $      17.3  $      40.3  $      33.8
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    (Per BOE)                    2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Cash                  $      2.27  $      1.67  $      2.16  $      1.75
	    Trust unit rights
	     incentive plan
	     (non-cash)                  0.22         0.23         0.19         0.21
	    -------------------------------------------------------------------------
	    Total G&A             $      2.49  $      1.90  $      2.35  $      1.96
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    >>

	    We continue to pursue G&A cost cutting measures however the transaction
costs on the senior notes and lower capital overhead recoveries have offset
our savings. We are maintaining our guidance for G&A expenses at $2.45/BOE,
which includes non-cash G&A costs of approximately $0.20/BOE.

	    Interest Expense

	    Interest expense includes interest on long-term debt, the premium
amortization on our US$175 million senior unsecured notes issued in June 2002,
unrealized gains and losses resulting from the change in fair value of our
interest rate swaps as well as the interest component on our cross currency
interest rate swap ("CCIRS"). See Note 5 for further details.
	    Interest on long-term debt excluding non-cash charges totaled $5.2
million and $10.8 million for the three and six months ended June 30, 2009,
compared to $12.9 million and $26.3 million respectively, for the same periods
in 2008. The decrease in 2009 was due to lower average outstanding
indebtedness and lower interest rates.
	    Non-cash interest charges totaled $16.4 million and $22.8 million for the
three and six months ended June 30, 2009, compared to $6.4 million and nil
respectively, for the same periods in 2008. The changes in the fair value of
our interest rate swaps and the interest component on our CCIRS that result
from movements in forward market interest rates cause non-cash interest to
fluctuate between periods.

	    The following table summarizes the cash and non-cash interest expense
recorded:

	    <<
	    Interest Expense    Three months ended June 30, Six months ended June 30,
	    ($ millions)                 2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Interest on
	     long-term debt       $       5.2  $      12.9  $      10.8  $      26.2
	    Non-cash interest
	     loss                        16.4          6.4         22.8          0.1
	    -------------------------------------------------------------------------
	    Total Interest
	     Expense              $      21.6  $      19.3  $      33.6  $      26.3
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    >>

	    As a result of the additional senior unsecured notes issued on June 18,
2009, approximately 74% of our debt is based on fixed interest rates and 26%
based on floating interest rates at June 30, 2009. Our average cash interest
rate for the first six months of 2009 was approximately 2%. For the remainder
of the year we expect our average cash interest cost to be approximately 6%,
which reflects the new senior notes and less outstanding bank indebtedness.

	    Capital Expenditures

	    During the three and six months ended June 30, 2009 development capital
spending was $35.6 million and $134.8 million respectively, compared to $88.0
million and $214.3 million during the same periods in 2008. The reduced
spending levels in 2009 reflect a more conservative development capital budget
versus 2008 due to a decrease in commodity prices. Our development capital
spending in 2009 has also decreased from $99.2 million in the first quarter to
$35.6 million in the second quarter which emphasizes our cautious spending
approach in the current commodity price environment. Our capital spending in
the first quarter of 2009 was focused on completing projects that were
initiated in the fourth quarter of 2008, whereas spending in the second
quarter of 2009 was generally focused on new projects. To date in 2009 we have
achieved a 99% success rate with our drilling program on 128 net wells.
	    Property acquisitions for the three and six months ended June 30, 2009
totaled $28.4 million and $30.4 million respectively, compared to $1.8 million
and $9.3 million for the same periods in 2008. The majority of our 2009 second
quarter spending was related to a property acquisition in southeast
Saskatchewan that included approximately 200 BOE/day of non-operated Bakken
production and 11 net sections of land. Corporate acquisitions for the first
quarter of 2008 totaling approximately $1.7 billion were related to the Focus
acquisition.

	    Total net capital expenditures for 2009 and 2008 are outlined below:

	    <<
	                             Three months ended         Six months ended
	    Capital Expenditures            June 30,                 June 30,
	     ($ millions)                2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Development
	     expenditures         $      18.0  $      56.0  $      97.9  $     165.3
	    Plant and facilities         17.6         32.0         36.9         49.0
	    -------------------------------------------------------------------------
	      Development Capital        35.6         88.0        134.8        214.3
	    Office                        2.5          2.0          3.1          3.6
	    -------------------------------------------------------------------------
	      Sub-total                  38.1         90.0        137.9        217.9
	    Property acquisitions(1)     28.4          1.8         30.4          9.3
	    Corporate acquisitions          -            -            -      1,757.5
	    Property dispositions(1)     (1.7)        (0.1)        (1.7)        (2.2)
	    -------------------------------------------------------------------------
	    Total Net Capital
	     Expenditures         $      64.8  $      91.7  $     166.6  $   1,982.5
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    Capital Expenditures
	     financed with cash
	     flow                 $      64.8  $      91.7  $     166.6  $     226.0
	    Capital Expenditures
	     financed with debt
	     and equity                     -            -            -      1,756.5
	    -------------------------------------------------------------------------
	    Total Net Capital
	     Expenditures         $      64.8  $      91.7  $     166.6  $   1,982.5
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (1) Net of post-closing adjustments.
	    >>

	    With respect to our development capital spending we continue to favour
oil projects given the continued softness in natural gas prices with the
exception of those natural gas projects that may be supported by the Alberta
government's drilling incentive program. We are maintaining our 2009 guidance
of $300 million for annual development capital spending. However, if commodity
prices weaken further we may adjust our spending levels down.

	    Oil Sands

	    Our current oil sands portfolio includes the 100% owned and operated
Kirby steam assisted gravity drainage ("SAGD") project and a 11% minority
equity ownership interest in Laricina Energy Ltd., a private oil sands company
focused on SAGD development in the Athabasca oil sands. On April 17, 2009 we
announced that we are deferring further development of the Kirby project,
however several key activities are being completed in order to finalize
efforts underway at this time.
	    During the second quarter we focused on capturing the value of our
efforts to date and reducing costs should we decide to reinstate the project
at a later date. These activities included obtaining an updated independent
Kirby resource estimate and advancing the regulatory application, which we
expect should be completed early in 2010. During the quarter an updated
independent resource estimate was received and the best estimate of contingent
resources has increased 22% to 507 million barrels from 414 million barrels.
For additional information on contingent resource estimates, see "Information
Regarding Contingent Resource Estimates" at the end of the MD&A. We have also
redeployed the majority of our oil sands staff within the organization.
	    Our oil sands projects inception to date capitalized costs are $271.6
million. As these projects have not commenced commercial production all
associated costs, inclusive of acquisition expenditures, are capitalized and
excluded from our depletion calculation.

	    Depletion, Depreciation, Amortization and Accretion ("DDA&A")

	    DDA&A of property, plant and equipment ("PP&E") is recognized using the
unit-of-production method based on proved reserves.
	    For the three months ended June 30, 2009, DDA&A increased to $19.05/BOE
compared to $18.93/BOE during the corresponding period in 2008. For the six
months ended June 30, 2009, DDA&A increased to $19.03/BOE compared to
$18.12/BOE during the same period in 2008. The increase is primarily due to
additional PP&E as a result of the Focus acquisition.
	    No impairment of the Fund's assets existed at June 30, 2009 using
year-end reserves updated for acquisitions, divestitures, and management's
estimates of future prices.

	    Goodwill

	    The goodwill balance of $624.7 million arose as a result of previous
corporate acquisitions and represents the excess of the total purchase price
over the fair value of the net identifiable assets and liabilities acquired.
	    Accounting standards require the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. No goodwill impairment exists as at June 30, 2009.

	    Asset Retirement Obligations

	    In connection with our operations, we anticipate we will incur
abandonment and reclamation costs for surface leases, wells, facilities and
pipelines. Total future asset retirement obligations are estimated by
management based on Enerplus' net ownership interest in wells and facilities,
estimated costs to abandon and reclaim the wells and facilities, and the
estimated timing of the costs to be incurred in future periods. Enerplus has
estimated the net present value of its total asset retirement obligations to
be approximately $211.4 million at June 30, 2009 compared to $207.4 million at
December 31, 2008.
	    The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation, and asset retirement
obligations settled during the period.

	    Three months ended June 30, Six months ended June 30,
	    ($ millions)                 2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Total Amortization
	    and Accretion of
	    Asset Retirement
	    Obligations          $       8.4  $       8.2  $      17.0  $      15.4
	    Asset Retirement
	    Obligations
	    Settled              $       2.5  $       4.8  $       6.2  $       8.8
	    -------------------------------------------------------------------------

	    The timing of actual asset retirement costs will differ from the timing
of amortization and accretion charges. Actual asset retirement costs will be
incurred over the next 66 years with the majority between 2038 and 2047. For
accounting purposes, the asset retirement cost is amortized using a
unit-of-production method based on proved reserves before royalties while the
asset retirement obligation accretes until the time the obligation is settled.

	    Taxes

	    Future Income Taxes

	    Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
	    Our future income tax recovery was $32.9 million and $59.0 million for
the three and six months ended June 30, 2009 respectively, compared to a
recovery of $50.4 million and $85.6 for the same periods in 2008. The
decreased recovery is mainly due to lower taxable income transferred to the
Fund in 2009.

	    Current Income Taxes

	    In our current structure, payments are made by our operating entities to
the Fund which ultimately transfers both the income and future tax liability
to our unitholders. As a result, we expect minimal cash income taxes to be
paid by our Canadian operating entities in 2009. A current tax recovery of
$5.3 million and $7.9 million was recorded for the three and six months ended
June 30, 2008 respectively, related to the recovery of income taxes paid by
Focus as a result of the acquisition.
	    The amount of current taxes recorded throughout the year with respect to
our U.S. operations is dependent upon income levels and the timing of both
capital expenditures and the repatriation of funds to Canada. For the three
and six months ended June 30, 2009, we recorded current income taxes of $1.8
million and $2.6 million respectively, compared to $21.5 million and $33.7
million during the same periods in 2008. The decrease in current taxes is due
to a decrease in net income.
	    We continue to expect our U.S. current income taxes to average
approximately 10% of our cash flow from U.S. operations for 2009.

	    Net Income/(Loss)

	    Our net loss for the second quarter of 2009 was $3.6 million or $0.02 per
trust unit compared to net income of $112.2 million or $0.68 per trust unit
for the same period in 2008. Net income for the six months ended June 30, 2009
was $48.2 million or $0.29 per trust unit compared to $233.6 million or $1.50
per trust unit for the same period in 2008. The $185.4 million decrease in net
income for the six months ended June 30, 2009 was primarily due to a decrease
in oil and gas sales of $631.5 million which was partially offset by an
increase in commodity derivative instrument gains of $366.7 million and a
decrease in royalties of $122.8 million.

	    Cash Flow from Operating Activities ("Cash flow")

	    Cash flow for the three and six months ended June 30, 2009 was $210.6
million ($1.27 per trust unit) and $380.0 million ($2.29 per trust unit)
respectively, compared to $364.5 million ($2.22 per trust unit) and $620.7
million ($3.98 per trust unit) for the three and six months ended June 30,
2008. The decrease in cash flow per unit is largely due to a lower weighted
average sales price partially offset by cash gains on our commodity derivative
instruments, lower royalties and decreases in our non-cash operating working
capital.

	    Selected Financial Results

	    <<
	                  Three months ended June 30,   Three months ended June 30,
	                              2009                          2008
	    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
	     production       Cash   & Other                Cash   & Other
	     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
	    -------------------------------------------------------------------------
	    Production
	     per day                            94,501                       100,188
	    -------------------------------------------------------------------------
	    Weighted
	     average sales
	     price (2)     $ 35.60   $     -   $ 35.60   $ 80.56   $     -   $ 80.56
	    Royalties        (6.28)        -     (6.28)   (15.14)        -    (15.14)
	    Commodity
	     derivative
	     instruments      4.95     (5.80)    (0.85)   (7.03)    (17.65)   (24.68)
	    Operating costs  (9.58)    (0.35)    (9.93)   (9.43)         -     (9.43)
	    General and
	     administrative  (2.27)    (0.22)    (2.49)   (1.67)     (0.23)    (1.90)
	    Interest
	     expense, net
	     of other
	     income          (0.61)    (1.90)    (2.51)   (1.37)     (0.70)    (2.07)
	    Foreign
	     exchange
	     gain/(loss)      1.63     (0.16)     1.47     0.05       0.10      0.15
	    Current income
	     tax             (0.21)        -     (0.21)   (1.78)         -     (1.78)
	    Restoration and
	     abandonment
	     cash costs      (0.29)     0.29         -    (0.52)      0.52         -
	    Depletion,
	     depreciation,
	     amortization
	     and accretion       -    (19.05)   (19.05)       -     (18.93)   (18.93)
	    Future income
	     tax
	    recovery/
	    (expense)            -      3.83      3.83        -       5.53      5.53
	    -------------------------------------------------------------------------
	    Total per BOE $  22.94  $ (23.36) $  (0.42) $  43.67  $ (31.36) $  12.31
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (1) Cash flow from operating activities before changes in non-cash
	        operating working capital.
	    (2) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.



	                   Six months ended June 30,     Six months ended June 30,
	                              2009                          2008
	    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
	     production       Cash   & Other                Cash   & Other
	     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
	    -------------------------------------------------------------------------
	    Production
	     per day                            94,739                        94,681
	    -------------------------------------------------------------------------
	    Weighted
	     average sales
	     price (2)     $ 35.42   $     -   $ 35.42   $ 71.85   $     -   $ 71.85
	    Royalties        (6.36)        -     (6.36)   (13.46)        -    (13.46)
	    Commodity
	     derivative
	     instruments      5.16     (2.17)     2.99     (4.35)   (13.95)   (18.30)
	    Operating costs  (9.77)    (0.12)    (9.89)    (9.21)     0.04     (9.17)
	    General and
	     administrative  (2.16)    (0.19)    (2.35)    (1.75)    (0.21)    (1.96)
	    Interest
	     expense, net
	     of other
	     income          (0.62)    (1.33)    (1.95)    (1.10)    (0.01)    (1.11)
	    Foreign
	     exchange
	     gain/(loss)      0.69         -      0.69         -     (0.13)    (0.13)
	    Current income
	     tax             (0.15)        -     (0.15)    (1.49)        -     (1.49)
	    Restoration and
	     abandonment
	     cash costs      (0.36)     0.36         -     (0.51)     0.51         -
	    Depletion,
	     depreciation,
	     amortization
	     and accretion       -    (19.03)   (19.03)        -    (18.12)   (18.12)
	    Future income
	     tax recovery/
	     (expense)           -      3.44      3.44         -      4.97      4.97
	    Gain on sale of
	     marketable
	     securities(3)       -         -         -         -      0.48      0.48
	    -------------------------------------------------------------------------
	    Total per BOE  $ 21.85   $(19.04)  $  2.81   $ 39.98   $(26.42)  $ 13.56
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (1) Cash flow from operating activities before changes in non-cash
	        operating working capital.
	    (2) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    (3) Gain on sale of marketable securities was a cash item, however it is
	        included in cash flow from investing activities not cash flow from
	        operating activities.

	    Selected Canadian and U.S. Results

	    The following tables provide a geographical analysis of key operating and
financial results for the three and six months ended June 30, 2009 and 2008.

	    (CDN$ millions,    Three months ended            Three months ended
	     except per           June 30, 2009                 June 30, 2008
	     unit amounts)  Canada      U.S.     Total    Canada      U.S.     Total
	    -------------------------------------------------------------------------
	    Daily
	     Production
	     Volumes
	      Natural gas
	       (Mcf/day)   323,941    14,252   338,193   346,554    12,795   359,349
	      Crude oil
	       (bbls/day)   25,221     8,494    33,715    25,652     9,834    35,486
	      Natural gas
	       liquids
	       (bbls/day)    4,420         -     4,420     4,810         -     4,810
	      Total Daily
	       Sales
	       (BOE/day)    83,632    10,869    94,501    88,221    11,967   100,188

	    Pricing (1)
	      Natural gas
	      (per Mcf)    $  3.45   $  4.34   $  3.49   $  9.80   $ 11.80   $  9.87
	      Crude oil
	       (per bbl)     59.56     60.53     59.80    112.41    118.27    114.04
	      Natural gas
	       liquids
	       (per bbl)     35.47        -      35.47     80.55         -     80.55

	    Capital
	     Expenditures
	      Development
	       capital and
	       office      $  31.8   $   6.3   $  38.1   $  76.5   $  13.5   $  90.0
	      Acquisitions
	       of oil and
	       gas
	       properties     28.1       0.3      28.4       2.0      (0.2)      1.8
	      Dispositions
	       of oil and
	       gas
	       properties     (1.7)        -      (1.7)     (0.1)        -      (0.1)

	    Revenues
	      Oil and gas
	       sales (1)   $ 253.7   $  52.5   $ 306.2   $ 614.8   $ 119.6   $ 734.4
	      Royalties (2)  (42.0)    (12.0)    (54.0)   (112.4)    (25.6)   (138.0)
	      Commodity
	       derivative
	       instruments
	       gain/(loss)    (7.3)        -      (7.3)   (225.0)        -    (225.0)

	    Expenses
	      Operating    $  81.9   $   3.5   $  85.4   $  80.8   $   5.2   $  86.0
	      General and
	       administra-
	       tive           19.8       1.6      21.4      16.0       1.3      17.3
	      Depletion,
	       depreciation,
	       amortization
	       and
	       accretion     141.5      22.3     163.8     149.6      22.9     172.5
	      Current income
	       taxes
	       (recovery)/
	       expense           -       1.8       1.8      (5.3)     21.5      16.2
	    -------------------------------------------------------------------------
	    (1) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    (2) U.S. royalties include state production tax.



	    (CDN$ millions,     Six months ended              Six months ended
	     except per           June 30, 2009                 June 30, 2008
	     unit amounts)  Canada      U.S.     Total    Canada      U.S.     Total
	    -------------------------------------------------------------------------
	    Daily
	     Production
	     Volumes
	      Natural gas
	       (Mcf/day)   324,865    13,673   338,538   321,177    12,382   333,559
	      Crude oil
	       (bbls/day)   25,300     8,775    34,075    24,687     9,689    34,376
	      Natural gas
	       liquids
	       (bbls/day)    4,241         -     4,241     4,712         -     4,712
	      Total Daily
	       Sales
	       (BOE/day)    83,685     11,054   94,739    82,929    11,752    94,681

	    Pricing (1)
	      Natural gas
	       (per Mcf)   $  4.28   $  4.83   $  4.31   $  8.72   $ 10.42   $  8.79
	      Crude oil
	       (per bbl)     51.43     50.01     51.06     98.89    104.50    100.47
	      Natural gas
	       liquids
	       (per bbl)     37.91         -     37.91     75.29          -    75.29

	    Capital Expenditures
	      Development
	       capital and
	       office      $ 120.8   $  17.1   $ 137.9   $ 184.8   $  33.1   $ 217.9
	      Acquisitions
	       of oil and
	       gas
	       properties     29.9       0.5      30.4       9.4      (0.1)      9.3
	      Dispositions
	       of oil and
	       gas
	       properties     (1.7)        -      (1.7)     (2.2)        -      (2.2)

	    Revenues
	      Oil and gas
	       sales (1)   $ 516.0   $  91.4   $ 607.4  $1,030.3   $ 207.8  $1,238.1
	      Royalties (2)  (88.5)    (20.5)   (109.0)   (187.4)    (44.5)   (231.9)
	      Commodity
	       derivative
	       instruments
	       gain/(loss)    51.3         -      51.3    (315.4)        -    (315.4)

	    Expenses
	      Operating    $ 162.2   $   7.3   $ 169.5   $ 149.4   $   8.6   $ 158.0
	      General and
	       administra-
	       tive           36.8       3.5      40.3      31.1       2.7      33.8
	      Depletion,
	       depreciation,
	       amortization
	       and accretion 280.4      46.0     326.4     268.0      44.3     312.3
	      Current income
	       taxes
	       (recovery)/
	       expense           -       2.6      2.6      (7.9)     33.7      25.8
	    -------------------------------------------------------------------------
	    (1) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    (2) U.S. royalties include state production tax.
	    >>

	    Quarterly Financial Information

	    In general, crude oil and natural gas sales increased from 2007 to
mid-2008 due to increased commodity prices and increased production from the
Focus acquisition. Oil and gas sales decreased in the latter part of 2008 with
the sharp decline in commodity prices. During the second quarter of 2009 crude
oil prices have started to recover; however, this has largely been offset by
natural gas prices which have continued to decline since the start of the
year.
	    Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating costs and
changes in future tax provisions due to the SIFT tax and corporate tax rate
reductions. Furthermore, changes in the fair value of our commodity derivative
instruments and other financial instruments cause net income to continually
fluctuate between quarters.

	    <<

	    Quarterly Financial Information                         Net Income/(Loss)
	    ($ millions, except per                                  per trust unit
	    trust unit amounts)            Oil and    Net Income/  ------------------
	                                Gas Sales(1)     (Loss)     Basic    Diluted
	    -------------------------------------------------------------------------
	    2009
	    Second quarter                   $306.2      $(3.6)    $(0.02)    $(0.02)
	    First quarter                     301.2       51.8       0.31       0.31
	    ---------------------------------------------------
	    Total                            $607.4      $48.2      $0.29      $0.29
	    -------------------------------------------------------------------------
	    2008
	    Fourth quarter                   $418.3     $189.5      $1.15      $1.15
	    Third quarter                     647.8      465.8       2.82       2.82
	    Second quarter                    734.4      112.2       0.68       0.68
	    First quarter                     503.7      121.4       0.82       0.82
	    ---------------------------------------------------
	    Total                          $2,304.2     $888.9      $5.54      $5.53
	    -------------------------------------------------------------------------
	    2007
	    Fourth quarter                   $389.8      $98.7      $0.76      $0.76
	    Third quarter                     364.8       93.0       0.72       0.72
	    Second quarter                    382.5       40.1       0.31       0.31
	    First quarter                     380.0      107.9       0.88       0.87
	    ---------------------------------------------------
	    Total                          $1,517.1     $339.7      $2.66      $2.66
	    -------------------------------------------------------------------------
	    (1) Net of oil and gas transportation costs, but before the effects of
	        commodity derivative instruments.
	    >>

	    Liquidity and Capital Resources

	    Capital Markets and Enerplus' Credit Exposure

	    We are gradually seeing some improvements in the financial markets as the
global economic crisis is showing signs of easing. During the second quarter
we saw a significant increase in activity in the equity and debt capital
markets. On June 18, 2009 we successfully closed a private offering of senior
unsecured notes that raised gross proceeds of approximately $338.7 million.
The proceeds of the offering were used to pay down bank indebtedness giving us
additional financial flexibility to pursue acquisitions. See the Long-Term
Debt section of this MD&A for more information on the terms of the new notes.
	    Low crude oil and natural gas prices are placing a greater emphasis on
evaluating credit capacity, understanding counterparty credit risk and overall
liquidity concerns. We discuss these risks below as they relate to our credit
facility, oil and gas sales counterparties, financial derivative
counterparties and joint venture partners.

	    <<
	    Credit Facility
	    ---------------
	    >>

	    Enerplus' $1.4 billion bank credit facility is an unsecured,
covenant-based, three-year term agreement ending November 2010, a copy of
which was filed on March 18, 2008 as a "Material document" on the Fund's SEDAR
profile at www.sedar.com. Of the thirteen syndicate members in Enerplus'
facility, seven are major Canadian banks which collectively represent
approximately $985 million or 70% of the commitments under the $1.4 billion
facility. We have the ability to request an extension of the facility each
year or repay the entire balance at the end of the term. Borrowing costs under
the facility range between 55.0 and 110.0 basis points over bankers'
acceptance rates, with our current borrowing cost being 55.0 basis points over
bankers' acceptance rates. Our borrowing costs are likely to increase upon
renewal of our credit facility as extension fees and pricing for drawn and
undrawn balances have generally increased in the marketplace due to the global
economic credit crisis. At June 30, 2009 we have drawn only $96.9 million or
approximately 7% of the $1.4 billion facility as the proceeds of the June 18,
2009 note offering were used to pay down credit facility debt. At June 30,
2009, we are in compliance with all covenants under the credit facility.
	    Our exposure to our lenders relates to their potential inability to
provide funding. Should a lender be unable or choose not to fund, other
lenders have the right, but not the obligation, to increase their commitment
levels to cover the shortfall. Failure to fund would be considered a breach of
contract and could result in potential damages in our favour, however the
likelihood of substantiating and receiving damages is unknown. We have not
experienced any funding issues under the facility to date.

	    <<
	    Oil and Gas Sales Counterparties
	    --------------------------------
	    >>

	    The Fund's oil and gas receivables are with customers in the petroleum
and natural gas business and are subject to normal credit risks. Concentration
of credit risk is mitigated by marketing production to numerous purchasers
under normal industry sale and payment terms. A credit review process is in
place to assess and monitor our counterparties' credit worthiness on a regular
basis. This process involves reviewing and ratifying our corporate credit
guidelines, assessing the credit ratings of our counterparties and setting
exposure limits. When warranted we obtain financial assurances such as letters
of credit, parental guarantees, or third party insurance to mitigate our
credit risk. This process is utilized for both our oil and gas sales
counterparties as well as our financial derivative counterparties.

	    <<
	    Financial Derivative Counterparties
	    -----------------------------------
	    >>

	    The Fund is exposed to credit risk in the event of non-performance by our
financial counterparties regarding our derivative contracts. The Fund
mitigates this risk by entering into transactions with major financial
institutions, the majority of which are members of our bank syndicate. We have
International Swaps and Derivatives Association ("ISDA") agreements in place
with the majority of our financial counterparties. These agreements provide
some credit protection in that they generally allow parties to aggregate
amounts owing to each other under all outstanding transactions and settle with
a single net amount in the case of a credit event. Absent an ISDA we rely on
long form confirmations which provide Enerplus with similar credit protection.
At June 30, 2009, we had $88.0 million in mark-to-market assets offset by
$53.6 million of mark-to-market liabilities consisting of net asset positions
of $27.0 million with major Canadian institutions and $7.4 million with U.S.
institutions.
	    We will continue to monitor developments in the financial markets that
could impact the creditworthiness of our financial counterparties. To date we
have not experienced any losses due to non-performance by our derivative
counterparties.

	    <<
	    Joint Venture Partners
	    ----------------------
	    >>

	    We attempt to mitigate the credit risk associated with our joint interest
receivables by reviewing and actively following up on older accounts. In
addition, we are specifically monitoring our receivables against a watch list
of publicly traded companies that have high debt-to-cash flow ratios or highly
drawn bank facilities. We do not anticipate any significant issues in the
collection of our joint interest receivables at this time. However, if the
current low commodity prices and tight capital markets prevail, there is a
risk of increased bad debts related to our industry partners.

	    Distribution Policy

	    The amount of cash distributions is proposed by management and approved
by the Board of Directors. We continually assess distribution levels with
respect to anticipated cash flows, debt levels, capital spending plans and
capital market conditions. The level of cash withheld varies and is dependent
upon numerous factors, the most significant of which are the prevailing
commodity price environment, our current levels of production, debt
obligations, funding requirements for our development capital program and our
access to equity markets.
	    The sharp decrease in commodity prices has resulted in a decrease in our
overall cash flows relative to 2008 levels. This commodity price downturn,
combined with the ongoing uncertainty in the capital markets, has reinforced
our belief in the importance of maintaining strong financial flexibility. We
have maintained our monthly distribution rate of $0.18 per unit distribution
since February 2009 and we intend to manage our distribution levels and
capital spending in order to minimize increases in our debt levels and
preserve our balance sheet strength for future acquisitions.
	    Although we intend to continue to make cash distributions to our
unitholders, these distributions are not guaranteed. To the extent there is
taxable income at the trust level, determined in accordance with the Canadian
Income Tax Act, the distribution of that taxable income is non-discretionary.

	    Sustainability of our Distributions and Asset Base

	    As an oil and gas producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future crude oil and natural gas production
is highly dependent on our success in exploiting our asset base and acquiring
or developing additional reserves. To the extent we are unsuccessful in these
activities, our cash distributions could be reduced.
	    Development activities and acquisitions may be funded internally by
withholding a portion of cash flow or through external sources of capital such
as debt or the issuance of equity. To the extent that we withhold cash flow to
finance these activities, the amount of cash distributions to our unitholders
may be reduced. Should external sources of capital become limited or
unavailable, our ability to make the necessary development expenditures and
acquisitions to maintain or expand our asset base may be impaired and
ultimately reduce the amount of cash distributions.
	    Enerplus currently has approximately $9.5 billion of safe harbour growth
capacity within the context of the Canadian Government's "normal growth"
guidelines for SIFT's.

	    Cash Flow from Operating Activities, Cash Distributions and Payout Ratio

	    Cash flow from operating activities and cash distributions are reported
on the Consolidated Statements of Cash Flows. During the second quarter of
2009, cash distributions of $89.6 million were funded entirely through cash
flow of $210.6 million. For the six months ended June 30, 2009, our cash
distributions were $179.1 million and were funded entirely through cash flow
of $380.0 million.
	    Our payout ratio, which is calculated as cash distributions divided by
cash flow, was 43% and 47% for the three and six months ended June 30, 2009
respectively, compared to 56% and 64% for the same periods in 2008. The
decrease in our payout ratio is due to the reduction in our monthly cash
distributions along with fluctuations in our working capital balances that
impact cash flow. Our adjusted payout ratio, which is calculated as cash
distributions plus development capital and office expenditures divided by cash
flow, was 61% for the second quarter and 83% for the six months ended June 30,
2009. See "Non-GAAP Measures" above. Our reduced capital spending levels
combined with decreases in our non-cash operating working capital in the
second quarter has reduced the second quarter adjusted payout ratio to 61%
from 112% in the first quarter of 2009. We expect to support our distributions
and capital expenditures with our cash flow over the remaining quarters in
2009, however, we may fund acquisitions and growth through additional debt and
equity if required. We continue to have conservative debt levels with a debt
to trailing twelve month cash flow ratio of 0.7x at June 30, 2009 and a debt
to annualized year-to-date 2009 cash flow ratio of 1.1x.
	    For the three months ended June 30, 2009, our cash distributions exceeded
our net income/(loss) by $93.2 million (2008 - $90.1 million), however net
income includes $203.4 million of non-cash items (2008 - $290.6 million). For
the six months ended June 30, 2009 our cash distributions exceeded our net
income by $130.9 million (2008 - $161.1 million) which included $332.6 million
of non-cash items (2008 - $472.3 million). Non-cash items such as changes in
the fair value of our derivative instruments and future income taxes do not
reduce or increase our cash flow. Future income taxes can fluctuate from
period to period as a result of changes in tax rates as well as changes in
interest, royalties and dividends from our operating subsidiaries paid to the
Fund. In addition, we believe that other non-cash charges such as DDA&A are
not a good proxy for the cost of maintaining our productive capacity as they
are based on the historical costs of our PP&E and not the fair market value of
replacing those assets within the context of the current environment.
	    It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. As a result, we do not
distinguish maintenance capital separately from development capital spending.
The level of investment in a given period may not be sufficient to replace
productive capacity given the natural declines associated with oil and natural
gas assets. In these instances a portion of the cash distributions paid to
unitholders may represent a return of the unitholders' capital.

	    The following table compares cash distributions to cash flow and net
income:

	    <<
	                            Three months  Six months  Year ended  Year ended
	                                   ended       ended    December    December
	    ($ millions, except          June 30,    June 30,         31,         31,
	    per unit amounts)               2009        2009        2008        2007
	    -------------------------------------------------------------------------
	    Cash flow from operating
	     activities                   $210.6      $380.0    $1,262.8      $868.5
	    Cash distributions              89.6       179.1       786.1       646.8
	    -------------------------------------------------------------------------
	    Excess of cash flow over
	     cash distributions           $121.0      $200.9      $476.7      $221.7

	    Net income/(loss)              $(3.6)      $48.2      $888.9      $339.7
	    (Shortfall)/excess of net
	     income/(loss) over cash
	     distributions                 (93.2)     (130.9)      102.8      (307.1)

	    Cash distributions per
	     weighted average trust
	     unit                          $0.54       $1.08       $4.90       $5.07
	    Payout ratio(1)                   43%         47%         62%         74%
	    -------------------------------------------------------------------------
	    (1) Based on cash distributions divided by cash flow from operating
	        activities.
	    >>

	    Long-Term Debt

	    On June 18, 2009, we closed a private offering of senior unsecured notes
to U.S. and Canadian institutional investors that raised gross proceeds of
approximately $338.7 million. The notes were priced at par and have
semi-annual interest payments on June 18 and December 18 of each year. The
proceeds from the offering repaid a portion of our outstanding bank debt,
which increased the available credit under our bank facility. The three new
note series along with the terms and rates are summarized in the table below.

	    <<
	    Amount                            Term                       Coupon Rate
	    -------------------------------------------------------------------------
	    US$225 million   12 year amortizing term repayable 2017 - 2021    7.97%
	    US$40 million     6 year term repayable in 2015                   6.82%
	    CDN$40 million    6 year term repayable in 2015                   6.37%
	    -------------------------------------------------------------------------
	    >>

	    Long-term debt at June 30, 2009 was $713.7 million, an increase of $49.4
million from $664.3 million at December 31, 2008. Long-term debt at June 30,
2009 was comprised of $96.9 million of bank indebtedness and $616.8 million of
senior unsecured notes.
	    Our bank indebtedness of $96.9 million at June 30, 2009 decreased $284.0
million from $380.9 million at December 31, 2008. This decrease is primarily
due to the proceeds of the June 18, 2009 private offering of senior unsecured
notes partially offset by funding working capital requirements.
	    Our working capital at June 30, 2009, excluding cash, current deferred
financial assets and credits and future income taxes, increased by $91.5
million compared to December 31, 2008. This change is due to decreased
accounts payable that resulted from lower capital spending activity along with
decreased distributions payable as a result of the reduction in our monthly
distributions.

	    We continue to maintain a conservative balance sheet as demonstrated
below:

	    <<
	    Financial Leverage and Coverage        June 30, 2009   December 31, 2008
	    -------------------------------------------------------------------------
	    Long-term debt to cash flow (12 month
	     trailing)                                     0.7 x               0.5 x
	    Cash flow to interest expense (12 month
	     trailing)                                    32.5 x              46.5 x
	    Long-term debt to long-term debt
	     plus equity                                     15%                13 %
	    -------------------------------------------------------------------------
	    Long-term debt is measured net of cash.
	    >>

	    Payments with respect to the bank facilities, senior unsecured notes and
other third party debt have priority over claims of and future distributions
to the unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At June 30, 2009,
we are in compliance with our debt covenants, the most restrictive of which
limits our long-term debt to three times trailing cash flow. Refer to "Debt of
Enerplus" in our Annual Information Form for the year ended December 31, 2008
for a detailed description of these covenants.
	    We anticipate that we will continue to have adequate liquidity under our
bank credit facility and from cash flow to fund planned development capital
spending and working capital requirements in 2009.

	    Accumulated Deficit

	    We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on the actual cash flow generated in
the period, whereas accumulated earnings are based on net income which
includes non-cash items such as DDA&A charges, derivative instrument
mark-to-market gains and losses, unit based compensation charges and future
income tax provisions.

	    Trust Unit Information

	    We had 166,022,000 trust units outstanding at June 30, 2009 compared to
164,709,000 trust units at June 30, 2008 and 165,590,000 trust units
outstanding at December 31, 2008. This includes 6,654,000 exchangeable limited
partnership units which are convertible at the option of the holder into 0.425
of an Enerplus trust unit (2,828,000 trust units). During the second quarter
of 2009, 187,000 partnership units were converted into 79,000 trust units.
	    During the three months ended June 30, 2009, 194,000 trust units (2008 -
683,000) were issued pursuant to the Trust Unit Monthly Distribution
Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights
incentive plan, net of redemptions. This resulted in $4.5 million (2008 -
$28.8 million) of additional equity to the Fund. For the six months ended June
30, 2009, $9.9 million of additional equity (2008 - $40.7 million) and 432,000
trust units (2008 - 1,000,000) were issued pursuant to the DRIP and the trust
unit rights incentive plan. For further details see Note 7.
	    The weighted average basic number of trust units outstanding for the six
months ended June 30, 2009 was 165,807,000 (2008 - 155,984,000). At July 29,
2009, we had 166,095,000 trust units outstanding including the equivalent
limited partnership units.

	    Income Taxes

	    The following is a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus trust units as capital property. The summary
is not exhaustive in nature and is not intended to provide legal or tax
advice. Investors or potential unitholders should consult their own legal or
tax advisors as to their particular tax consequences.

	    Canadian Unitholders

	    We qualify as a mutual fund trust under the Income Tax Act (Canada) and
accordingly, trust units of Enerplus are qualified investments for RRSPs,
RRIFs, RESPs, DPSPs and TFSAs. Each year we have historically transferred all
of our taxable income to the unitholders by way of distributions.
	    In computing income, unitholders are required to include the taxable
portion of distributions received in that year. An investor's adjusted cost
base ("ACB") in a trust unit equals the purchase price of the trust unit less
any non-taxable cash distributions received from the date of acquisition. To
the extent a unitholder's ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholder's ACB will be
brought to $nil.
	    For 2009, we estimate that 95% of cash distributions will be taxable and
5% will be a tax deferred return of capital. Actual taxable amounts may vary
depending on actual distributions which are dependent upon, among other
things, production, commodity prices and cash flow experienced throughout the
year.

	    U.S. Unitholders

	    U.S. unitholders who received cash distributions were subject to at least
a 15% Canadian withholding tax. The withholding tax is applied to both the
taxable and non-taxable portion of the distribution as computed under Canadian
tax law. U.S. taxpayers may be eligible for a foreign tax credit with respect
to Canadian withholding taxes paid.
	    For U.S. taxpayers, the taxable portion of cash distributions are
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. The
15% preferred rate of tax on "Qualified Dividends" is currently scheduled to
expire in 2010. We are unable to determine whether or to what extent the
preferred rate of tax on "Qualified Dividends" may be extended.
	    For 2009, we estimate that 90% of cash distributions will be taxable to
most U.S. investors and 10% will be a tax deferred return of capital. Actual
taxable amounts may vary depending on actual distributions which are dependent
upon production, commodity prices, and cash flow experienced throughout the
year.
	    In July 2009, we estimated our non-resident ownership to be 66%.

	    CHANGE IN INDEPENDENT RESERVES ENGINEER

	    Effective August 6, 2009, McDaniel & Associates Consultants Ltd.
("McDaniel"), has been appointed as our independent reserves evaluator for
Enerplus' Canadian conventional properties replacing Sproule Associates
Limited ("Sproule") in that capacity.  Reserve estimates are, by necessity,
projections and are based upon the professional judgement and experience of
the independent evaluator. McDaniel's reserve estimates may differ from the
previous estimates made by Sproule with respect to these properties and the
differences may be material.  GLJ Petroleum Consultants Ltd. has continued to
evaluate our contingent resources associated with our oil sands and we expect
Netherland Sewell Associates Inc. will continue to evaluate our U.S.
properties.

	    INTERNAL CONTROLS AND PROCEDURES

	    There were no changes in our internal control over financial reporting
during the period beginning on April 1, 2009 and ended on June 30, 2009 that
have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.

	    RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

	    <<
	    Convergence of Canadian GAAP with International Financial Reporting
	    Standards ("IFRS")
	    >>

	    In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP being converged with IFRS by 2011 for
public reporting entities. On February 13, 2008 the AcSB confirmed that IFRS
will be required for public companies beginning January 1, 2011.
	    In order to meet our reporting requirements and transition to IFRS we
have established a project team comprised of individuals from Finance,
Information Systems and Business Solutions, Tax, Investor Relations and
Management. Our transition plan consists of four main phases:

	    <<
	    -   An IFRS diagnostic phase which involves an assessment of the
	        differences between Canadian GAAP and IFRS,
	    -   An assessment and selection phase whereby we will determine
	        accounting policies for transition and our continuing IFRS accounting
	        policies,
	    -   An evaluation of our information systems, business processes,
	        procedures and controls to support the new reporting standards, and
	    -   Training and development throughout the organization.
	    >>

	    To date we have completed our IFRS diagnostic assessment and have started
to analyze and identify accounting policy choices, which include assessing the
impact on information systems and business processes. We have also provided
training to certain business groups which are impacted. We intend to generate
financial information in accordance with IFRS during 2010 to provide
comparative information for the 2011 financial statements.
	    In July 2009, the International Accounting Standards Board finalized an
amendment to IFRS 1, First-Time Adoption of International Financial Reporting
Standards, that allows a first-time adopter using full cost accounting to
elect to measure oil and gas assets at the date of transition to IFRS using
the amount determined based on the entity's previous GAAP. The effective date
is years beginning on or after January 1, 2010 with early adoption permitted.
Enerplus intends to use this election on adoption of IFRS.
	    The transition from current Canadian GAAP to IFRS is a significant
undertaking that may materially affect our reported financial position and
results of operations. As we have not yet finalized our accounting policies,
we are unable to quantify the impact of adopting IFRS on our financial
statements. In addition, due to anticipated changes to IFRS and International
Accounting Standards prior to our adoption of IFRS, our plan is subject to
change based on new facts and circumstances that arise after the date of this
MD&A.


	    <<
	    CONSOLIDATED BALANCE SHEETS

	    (CDN$ thousands) (Unaudited)            June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Assets
	    Current assets
	      Cash                                    $       175        $     6,922
	      Accounts receivable                         111,987            163,152
	      Deferred financial assets (Note 8)           83,697            121,281
	      Other current                                 8,398              3,783
	    -------------------------------------------------------------------------
	                                                  204,257            295,138
	    -------------------------------------------------------------------------
	    Property, plant and equipment (Note 2)      5,063,164          5,246,998
	    Goodwill                                      624,748            634,023
	    Deferred financial assets (Note 8)              4,281              6,857
	    Other assets (Note 8)                          47,116             47,116
	    -------------------------------------------------------------------------
	                                                5,739,309          5,934,994
	    -------------------------------------------------------------------------
	                                              $ 5,943,566        $ 6,230,132
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    Liabilities
	    Current liabilities
	      Accounts payable                        $   146,257        $   272,818
	      Distributions payable to unitholders         29,883             41,397
	      Future income taxes                          17,937             30,198
	      Deferred financial credits (Note 8)           9,985                  -
	    -------------------------------------------------------------------------
	                                                  204,062            344,413
	    -------------------------------------------------------------------------
	    Long-term debt (Note 4)                       713,711            664,343
	    Deferred financial credits (Note 8)            43,636             26,392
	    Future income taxes                           592,161            648,821
	    Asset retirement obligations (Note 3)         211,422            207,420
	    -------------------------------------------------------------------------
	                                                1,560,930          1,546,976
	    -------------------------------------------------------------------------
	    Equity
	    Unitholders' capital (Note 7)               5,484,505          5,471,336
	    Accumulated deficit                        (1,312,129)        (1,181,199)
	    Accumulated other comprehensive income          6,198             48,606
	    -------------------------------------------------------------------------
	                                               (1,305,931)        (1,132,593)
	                                                4,178,574          4,338,743
	    -------------------------------------------------------------------------
	                                              $ 5,943,566        $ 6,230,132
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

	    (CDN$ thousands)   Three months ended June 30,  Six months ended June 30,
	    (Unaudited)                  2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Accumulated income,
	     beginning of period  $ 3,227,605  $ 2,408,321  $ 3,175,819  $ 2,286,927
	    Net income/(loss)          (3,569)     112,230       48,217      233,624
	    -------------------------------------------------------------------------
	    Accumulated income,
	     end of period        $ 3,224,036  $ 2,520,551  $ 3,224,036  $ 2,520,551

	    Accumulated cash
	     distributions,
	     beginning of period  $(4,446,555) $(3,763,238) $(4,357,018) $(3,570,880)
	    Cash distributions        (89,610)    (202,346)    (179,147)    (394,704)
	    -------------------------------------------------------------------------
	    Accumulated cash
	     distributions, end
	     of period            $(4,536,165) $(3,965,584) $(4,536,165) $(3,965,584)

	    -------------------------------------------------------------------------
	    Accumulated deficit,
	     end of period        $(1,312,129) $(1,445,033) $(1,312,129) $(1,445,033)
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

	    (CDN$ thousands)   Three months ended June 30,  Six months ended June 30,
	    (Unaudited)                  2009         2008         2009         2008
	    -------------------------------------------------------------------------

	    Balance, beginning
	     of period            $    73,122  $   (87,505) $    48,606  $  (108,727)
	    Other comprehensive
	     income/(loss)            (66,924)      (5,623)     (42,408)      15,599
	    -------------------------------------------------------------------------
	    Balance, end of
	     period               $     6,198  $   (93,128) $     6,198  $   (93,128)
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    CONSOLIDATED STATEMENTS OF INCOME

	    (CDN$ thousands
	    except per trust
	    unit amounts)      Three months ended June 30,  Six months ended June 30,
	    (Unaudited)                  2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Revenues
	      Oil and gas sales   $   312,537  $   741,470  $   620,052  $ 1,251,539
	      Royalties               (54,009)    (138,040)    (109,047)    (231,876)
	      Commodity derivative
	       instruments (Note 8)    (7,336)    (225,015)      51,309     (315,394)
	      Other income                 31          411          175       15,527
	    -------------------------------------------------------------------------
	                              251,223      378,826      562,489      719,796
	    -------------------------------------------------------------------------
	    Expenses
	      Operating                85,389       85,974      169,519      157,990
	      General and
	       administrative          21,447       17,327       40,317       33,764
	      Transportation            6,356        7,127       12,657       13,444
	      Interest (Note 5)        21,575       19,313       33,572       26,301
	      Foreign exchange
	       (Note 6)               (12,611)      (1,408)     (11,758)       2,276
	      Depletion, depreciation,
	       amortization and
	       accretion              163,798      172,496      326,358      312,290
	    -------------------------------------------------------------------------
	                              285,954      300,829      570,665      546,065
	    -------------------------------------------------------------------------
	    Income/(loss) before
	     taxes                    (34,731)      77,997       (8,176)     173,731
	    Current taxes               1,777       16,211        2,616       25,752
	    Future income tax
	     recovery                 (32,939)     (50,444)     (59,009)     (85,645)
	    -------------------------------------------------------------------------
	    Net Income/(loss)     $    (3,569) $   112,230  $    48,217  $   233,624
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    Net income/(loss)
	     per trust unit
	      Basic               $     (0.02) $      0.68  $      0.29  $      1.50
	      Diluted             $     (0.02) $      0.68  $      0.29  $      1.50
	    -------------------------------------------------------------------------
	    Weighted average
	     number of trust
	     units outstanding
	     (thousands)(1)
	      Basic                   165,899      164,483      165,807      155,984
	      Diluted                 166,264      164,633      165,807      156,102
	    -------------------------------------------------------------------------
	    (1) Includes the exchangeable limited partnership units.


	    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	    (CDN$ thousands)   Three months ended June 30,  Six months ended June 30,
	    (Unaudited)                  2009         2008         2009         2008
	    -------------------------------------------------------------------------

	    Net income/(loss)     $    (3,569) $   112,230  $    48,217  $   223,624
	    -------------------------------------------------------------------------
	    Other comprehensive
	     income/(loss),
	     net of tax:
	      Unrealized gain
	       on marketable
	       securities                   -            -            -        2,578
	      Realized gain on
	       marketable securities
	       included in net income       -            -            -       (6,158)
	      Gains and losses
	       on derivatives
	       designated as hedges
	       in prior periods
	       included in net income       -            -            -           74
	    Change in cumulative
	     translation adjustment   (66,924)      (5,623)     (42,408)      19,105
	    -------------------------------------------------------------------------
	    Other comprehensive
	     income/(loss)            (66,924)      (5,623)     (42,408)      15,599
	    -------------------------------------------------------------------------
	    Comprehensive
	     income/(loss)        $   (70,493) $   106,607  $     5,809  $   239,223
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------


	    CONSOLIDATED STATEMENTS OF CASH FLOWS

	                                Three months ended          Six months ended
	    (CDN$ thousands)                  June 30,                  June 30,
	    (Unaudited)                  2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Operating Activities
	    Net income/(loss)     $    (3,569) $   112,230  $    48,217  $   233,624
	    Non-cash items
	     add/(deduct):
	      Depletion,
	       depreciation,
	       amortization and
	       accretion              163,798      172,496      326,358      312,290
	      Change in fair
	       value of derivative
	       instruments (Note 8)    84,110      168,787       67,389      235,259
	      Unit based compensation
	       (Note 7)                 1,877        2,094        3,256        3,580
	      Foreign exchange on
	       translation of
	       senior notes (Note 6)  (13,270)      (2,158)      (5,033)       7,075
	      Future income tax       (32,939)     (50,444)     (59,009)     (85,645)
	      Amortization of senior
	       notes premium             (192)        (157)        (394)        (310)
	      Reclassification
	       adjustments from AOCI
	       to net income                -            -            -           92
	    Gain on sale of
	     marketable securities          -            -            -       (8,263)
	    Asset retirement
	     obligations settled
	     (Note 3)                  (2,530)      (4,747)      (6,182)      (8,767)
	    -------------------------------------------------------------------------
	                              197,285      398,101      374,602      688,935
	    Decrease/(Increase) in
	     non-cash operating
	     working capital           13,323      (33,644)       5,394      (68,262)
	    -------------------------------------------------------------------------
	    Cash flow from operating
	     activities               210,608      364,457      379,996      620,673
	    -------------------------------------------------------------------------
	    Financing Activities
	    Issue of trust units,
	     net of issue costs
	     (Note 7)                   4,513       28,811        9,913       40,696
	    Cash distributions to
	     unitholders              (89,610)    (202,346)    (179,147)    (394,704)
	    Decrease in bank credit
	     facilities              (350,857)     (68,656)    (283,940)     (36,054)
	    Issuance of senior
	     unsecured notes          338,735            -      338,735            -
	    Decrease/(Increase) in
	     non-cash financing
	     working capital               35          241      (11,514)      14,658
	    -------------------------------------------------------------------------
	    Cash flow from financing
	     activities               (97,184)    (241,950)    (125,953)    (375,404)
	    -------------------------------------------------------------------------
	    Investing Activities
	    Capital expenditures      (38,013)     (89,961)    (137,887)    (217,884)
	    Property acquisitions     (28,416)      (1,740)     (30,393)      (9,289)
	    Property dispositions       1,723           86        1,736        2,208
	    Proceeds on sale of
	     marketable securities          -            -            -       18,320
	    Increase in non-cash
	     investing working
	     capital                  (46,633)     (30,218)     (93,034)     (40,636)
	    -------------------------------------------------------------------------
	    Cash flow from investing
	     activities              (111,339)    (121,833)    (259,578)    (247,281)
	    -------------------------------------------------------------------------
	    Effect of exchange rate
	     changes on cash           (2,035)      (1,404)      (1,212)       1,033
	    -------------------------------------------------------------------------
	    Change in cash                 50         (730)      (6,747)        (979)
	    Cash, beginning of period     125        1,453        6,922        1,702
	    -------------------------------------------------------------------------
	    Cash, end of period    $      175  $       723  $       175  $       723
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    Supplementary Cash
	     Flow Information
	    Cash income taxes
	     (received)/paid       $  (22,790) $    24,756  $   (22,790) $    33,758
	    Cash interest paid     $    7,198  $    17,980  $     9,899  $    26,298



	    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

	    1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

	    The interim consolidated financial statements of Enerplus Resources Fund
	    ("Enerplus" or the "Fund") have been prepared by management following the
	    same accounting policies and methods of computation as the consolidated
	    financial statements for the fiscal year ended December 31, 2008. The
	    note disclosure requirements for annual statements provide additional
	    disclosure to that required for these interim statements. Accordingly,
	    these interim statements should be read in conjunction with the Fund's
	    consolidated financial statements for the year ended December 31, 2008.
	    All amounts are stated in Canadian dollars unless otherwise specified.

	    2.  PROPERTY, PLANT AND EQUIPMENT (PP&E)

	    ($ thousands)                           June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Property, plant and equipment             $ 8,612,868        $ 8,497,206
	    Accumulated depletion, depreciation and
	     accretion                                 (3,549,704)        (3,250,208)
	    -------------------------------------------------------------------------
	    Net property, plant and equipment         $ 5,063,164        $ 5,246,998
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    Capitalized development general and administrative ("G&A") expense of
	    $12,813,000 (2008 - $10,812,000) is included in PP&E for the six months
	    ended June 30, 2009. Excluded from PP&E for the depletion and
	    depreciation calculation is $271,555,000 (December 31, 2008 -
	    $257,608,000) related to oil sands projects which have not yet commenced
	    commercial production.

	    3.  ASSET RETIREMENT OBLIGATIONS

	    Following is a reconciliation of the asset retirement obligations:

	                                         Six months ended         Year ended
	    ($ thousands)                           June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Asset retirement obligations,
	     beginning of period                      $   207,420        $   165,719
	    Corporate acquisition                               -             36,784
	    Changes in estimates                            3,290              4,087
	    Property acquisition and development
	     activity                                         828              7,394
	    Dispositions                                     (318)              (110)
	    Asset retirement obligations settled           (6,182)           (18,308)
	    Accretion expense                               6,384             11,854
	    -------------------------------------------------------------------------
	    Asset retirement obligations, end
	     of period                                $   211,422        $   207,420
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    4.  LONG-TERM DEBT

	    ($ thousands)                           June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Bank credit facilities (a)                $    96,948        $   380,888
	    Senior notes (b)
	      CDN$40 million (Issued June 18, 2009)        40,000                  -
	      US$225 million (Issued June 18, 2009)       261,563                  -
	      US$40 million (Issued June 18, 2009          46,500                  -
	      US$54 million (Issued October 1, 2003)       62,775             66,128
	      US$175 million (Issued June 19, 2002)(x)    205,925            217,327
	    -------------------------------------------------------------------------
	    Total long-term debt                      $   713,711        $   664,343
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (x) The June 19, 2010 principal repayment of US$35 million has not been
	        included in current liabilities as we expect to refinance this amount
	        with our long-term bank credit facility.

	    (a) Unsecured Bank Credit Facility

	    Enerplus currently has a $1.4 billion unsecured covenant based facility
	    that matures November 18, 2010. The facility is extendible each year with
	    a bullet payment required at maturity. Various borrowing options are
	    available under the facility including prime rate based advances and
	    bankers' acceptance loans. This facility carries floating interest rates
	    that are expected to range between 55.0 and 110.0 basis points over
	    bankers' acceptance rates, depending on Enerplus' ratio of senior debt to
	    earnings before interest, taxes and non-cash items. The weighted average
	    interest rate on the facility for the six months ended June 30, 2009 was
	    1.2% (June 30, 2008 - 4.0%).

	    (b) Senior Unsecured Notes

	    On June 18, 2009 Enerplus closed a private offering of senior unsecured
	    notes raising gross proceeds of approximately $338,735,000. The terms and
	    rates of Enerplus' outstanding senior unsecured notes are detailed below:


	    ($ thousands)
	    -------------------------------------------------------------------------
	     Issue                Coupon    Interest     Maturity
	     Date     Principal    Rate   Payment Dates    Date    Term
	    -------------------------------------------------------------------------
	    June 18,  US $225,000  7.97%   June 18 and   June 18,  Principal payments
	    2009                           December 18   2021      required in 5
	                                                           equal installments
	                                                           beginning June 18,
	                                                           2017
	    -------------------------------------------------------------------------
	    June 18,  US $40,000   6.82%   June 18 and   June 18,  Bullet payment on
	    2009                           December 18   2015      maturity
	    -------------------------------------------------------------------------
	    June 18,  CDN $40,000  6.37%   June 18 and   June 18,  Bullet payment on
	    2009                           December 18   2015      maturity
	    -------------------------------------------------------------------------
	    October   US $54,000   5.46%   April 1 and   October   Principal payments
	    1, 2003                        October 1     1, 2015   required in 5
	                                                           equal installments
	                                                           beginning October
	                                                           1, 2011
	    -------------------------------------------------------------------------
	    June 19,  US $175,000  6.62%   June 19 and   June 19,  Principal payments
	    2002                           December 19   2014      required in 5
	                                                           equal installments
	                                                           beginning June 19,
	                                                           2010
	    -------------------------------------------------------------------------

	    In September 2007 Enerplus entered into foreign exchange swaps that
	    effectively fix the five principal payments on the US$54,000,000 senior
	    unsecured notes at a CDN/US exchange rate of 0.98 or CDN$55,080,000.

	    Concurrent with the issuance of the US$175,000,000 senior notes on June
	    19, 2002, the Fund entered into a cross currency and interest rate swap
	    ("CCIRS") with a syndicate of financial institutions. Under the terms of
	    the swap, the amount of the notes was effectively fixed for purposes of
	    interest and principal repayments at a notional amount of CDN
	    $268,328,000. Interest payments are made on a floating rate basis, set at
	    the rate for three-month Canadian bankers' acceptances, plus 1.18%.

	    5.  INTEREST EXPENSE

	                        Three months ended June 30, Six months ended June 30,
	    ($ thousands)                2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Realized
	      Interest on
	       long-term debt         $ 5,212      $12,918      $10,767      $26,263
	    Unrealized
	      (Gain)/loss on cross
	       currency interest
	       rate swap               17,904        7,219       25,868       (1,125)
	      (Gain)/loss on
	       interest rate swaps     (1,349)        (667)      (2,669)       1,473
	      Amortization of the
	       premium on senior
	       unsecured notes           (192)        (157)        (394)        (310)
	    -------------------------------------------------------------------------
	      Interest expense        $21,575      $19,313      $33,572      $26,301
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    6.  FOREIGN EXCHANGE

	                        Three months ended June 30, Six months ended June 30,
	    ($ thousands)                2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Realized
	      Foreign exchange
	       (gain)/loss           $(13,991)    $   (550)    $(11,626)    $     18
	    Unrealized
	      Foreign exchange
	       (gain)/loss on
	       translation of U.S.
	       dollar denominated
	       senior notes           (13,270)      (2,158)      (5,033)       7,075
	    Foreign exchange
	     (gain)/loss on cross
	     currency interest
	     rate swap                 10,643         (320)       2,325       (4,491)
	    Foreign exchange
	     (gain)/loss on
	     foreign exchange swaps     4,007        1,620        2,576         (326)
	    -------------------------------------------------------------------------
	    Foreign exchange
	     (gain)/loss             $(12,611)    $ (1,408)    $(11,758)    $  2,276
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    7.  UNITHOLDERS' CAPITAL

	    Unitholders' capital as presented on the Consolidated Balance Sheets
	    consists of trust unit capital, exchangeable limited partnership unit
	    capital and contributed surplus.

	                                          Six months ended     Year ended
	    Unitholders' capital ($ thousands)      June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Trust units                               $ 5,348,470        $ 5,328,629
	    Exchangeable limited partnership units        113,179            123,107
	    Contributed surplus                            22,856             19,600
	    -------------------------------------------------------------------------
	    Balance, end of period                    $ 5,484,505        $ 5,471,336
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (a) Trust Units

	    Authorized: Unlimited number of trust units

	                                 Six months ended             Year ended
	    (thousands)                   June 30, 2009           December 31, 2008
	    Issued:                     Units       Amount        Units       Amount
	    -------------------------------------------------------------------------
	    Balance, beginning of
	     period                   162,514   $5,328,629      129,813   $4,020,228
	    Issued for cash:
	      Pursuant to rights
	       incentive plan               -            -          210        6,755
	      Cancelled trust units                                (116)      (3,794)
	      Exchangeable limited
	       partnership units
	       exchanged                  248        9,928          786       31,444
	    Trust unit rights
	     incentive plan (non-cash)
	     - exercised                    -            -            -        3,642
	    DRIP(x), net of redemptions   432        9,913        1,671       63,761
	    Issued for acquisition of
	     corporate and property
	     interests (non-cash)           -            -       30,150    1,206,593
	    -------------------------------------------------------------------------
	                              163,194   $5,348,470      162,514   $5,328,629
	    Equivalent exchangeable
	     partnership units          2,828      113,179        3,076      123,107
	    -------------------------------------------------------------------------
	    Balance, end of period    166,022   $5,461,649      165,590   $5,451,736
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    (x) Distribution Reinvestment and Unit Purchase Plan

	    (b) Exchangeable Limited Partnership Units

	    The limited partnership units of Enerplus Exchangeable Limited
	    Partnership are exchangeable into Enerplus trust units at a ratio of
	    0.425 of an Enerplus trust unit for each limited partnership unit. During
	    the period January 1, 2009 to June 30, 2009, 584,000 exchangeable limited
	    partnership units were converted into 248,000 trust units. As at June 30,
	    2009, the 6,654,000 outstanding exchangeable limited partnership units
	    represent the equivalent of 2,828,000 trust units.

	                                 Six months ended             Year ended
	    (thousands)                   June 30, 2009           December 31, 2008
	    Issued:                     Units       Amount        Units       Amount
	    -------------------------------------------------------------------------
	    Assumed on February
	     13, 2008                   7,238     $123,107        9,087     $154,551
	    Exchanged for trust units    (584)      (9,928)      (1,849)     (31,444)
	    -------------------------------------------------------------------------
	    Balance, end of period      6,654     $113,179        7,238     $123,107
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (c) Contributed Surplus

	                                         Six months ended         Year ended
	    Contributed surplus ($ thousands)       June 30, 2009  December 31, 2008
	    -------------------------------------------------------------------------
	    Balance, beginning of period                  $19,600            $12,452
	    Trust unit rights incentive plan
	     (non-cash) - exercised                             -             (3,642)
	    Trust unit rights incentive plan
	     (non-cash) - expensed                          3,256              6,996
	       Cancelled trust units                            -              3,794
	    -------------------------------------------------------------------------
	    Balance, end of period                        $22,856            $19,600
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (d) Trust Unit Rights Incentive Plan

	    As at June 30, 2009 a total of 5,839,000 rights were issued and
	    outstanding pursuant to the Trust Unit Rights Incentive Plan ("Rights
	    Incentive Plan") with an average exercise price of $35.14 per right. This
	    represents 3.5% of the total trust units outstanding of which 2,646,000
	    rights, with an average exercise price of $45.11, were exercisable. Under
	    the Rights Incentive Plan, distributions per trust unit to Enerplus
	    unitholders in a calendar quarter which represent a return of more than
	    2.5% of the net PP&E of Enerplus at the end of such calendar quarter may
	    result in a reduction in the exercise price of the rights. Results for
	    the first two quarters of 2009 did not reduce the exercise price of the
	    outstanding rights.

	    The Fund uses a binomial lattice option-pricing model to calculate the
	    estimated fair value of rights granted under the plan. The following
	    assumptions were used to arrive at the estimate of fair value for rights
	    granted during the second quarter:

	    -------------------------------------------------------------------------
	    Dividend yield                                                     8.32%
	    Volatility                                                        45.62%
	    Risk-free interest rate                                            2.44%
	    Forfeiture rate                                                   12.40%
	    Right's exercise price reduction                                  $1.76
	    -------------------------------------------------------------------------

	    Non-cash compensation costs related to rights issued charged to general
	    and administrative for the three and six months ended June 30, 2009 were
	    $1,877,000 ($0.11 per unit) and $3,256,000 ($0.19 per unit) respectively.
	    Activity for the rights issued pursuant to the Rights Incentive Plan is
	    as follows:

	                               Six months ended             Year ended
	                                 June 30, 2009           December 31, 2008
	                           ------------------------   -----------------------
	                                          Weighted                 Weighted
	                               Number      Average       Number      Average
	                            of Rights     Exercise    of Rights     Exercise
	                               (000's)     Price(1)      (000's)     Price(1)
	    -------------------------------------------------------------------------
	    Trust unit rights
	     outstanding
	    Beginning of period         4,001       $45.05        3,404       $47.59
	      Granted                   1,987        17.24        1,403        42.00
	      Exercised                     -            -         (210)       32.22
	      Cancelled                  (149)       40.74         (596)       44.94
	    -------------------------------------------------------------------------
	    End of period               5,839       $35.14        4,001       $45.05
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------
	    Rights exercisable at
	     end of period              2,646       $45.11        2,024       $46.44
	    -------------------------------------------------------------------------
	    (1) Exercise price reflects grant prices less reduction in strike price
	        discussed above.

	    (e) Basic and Diluted per Trust Unit Calculations

	    Basic per-unit calculations are calculated using the weighted average
	    number of trust units and exchangeable limited partnership units
	    (converted at the 0.425 exchange ratio) outstanding during the period.
	    Diluted per-unit calculations include additional trust units for the
	    dilutive impact of rights outstanding pursuant to the Rights Plan.

	    Net income per trust unit has been determined based on the following:

	                                                 Six months ended June 30,
	    (thousands)                                            2009         2008
	    -------------------------------------------------------------------------
	    Weighted average units                              165,807      155,984
	    Dilutive impact of rights                                 -          118
	    -------------------------------------------------------------------------
	    Diluted trust units                                 165,807      156,102
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (f) Performance Trust Unit Plan

	    In 2007 the Fund adopted a Performance Trust Unit ("PTU") plan for
	    executives and employees. For the three and six months ended June 30,
	    2009 the Fund recorded cash compensation costs of $1,863,000 (2008 -
	    $1,217,000) and $3,689,000 (2008 - $2,300,000), respectively, under the
	    plan which are included in general and administrative expenses.

	    At June 30, 2009 there were 399,000 performance trust units outstanding.

	    (g) Restricted Trust Unit Plan

	    In 2009 the Fund adopted a new Restricted Trust Unit ("RTU") plan for
	    executives and employees, which will replace the PTU plan. Under the RTU
	    plan employees and officers receive cash compensation in relation to the
	    value of a specified number of underlying notional trust units. The
	    number of notional trust units awarded is variable to individuals and
	    they vest one-third at the end of each year for three years. Upon
	    vesting, plan participants receive a cash payment based on the value of
	    the underlying trust units plus notional accrued distributions.

	    For the three and six months ended June 30, 2009 the Fund recorded cash
	    compensation costs of $1,707,000 and $3,000,000, respectively, under the
	    plan which are included in general and administrative expenses.

	    At June 30, 2009 there were 894,000 RTU's outstanding.

	    8.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

	    (a) Carrying Value and Fair Value of Non-derivative Financial Instruments

	    i.  Cash

	    Cash is classified as held-for-trading and is reported at fair value.

	    ii. Accounts Receivable

	    Accounts receivable are classified as loans and receivables and are
	    reported at amortized cost. At June 30, 2009 the carrying value of
	    accounts receivable approximated their fair value.

	    iii. Marketable Securities

	    Marketable securities with a quoted market price in an active market are
	    classified as available-for-sale and are reported at fair value, with
	    changes in fair value recorded in other comprehensive income. During 2009
	    the fund did not hold any investments in publicly traded marketable
	    securities.

	    Marketable securities without a quoted market price in an active market
	    are reported at cost unless an other than temporary impairment exists. As
	    at June 30, 2009 the Fund reported investments in marketable securities
	    of private companies at cost of $47,116,000 (December 31, 2008 -
	    $47,116,000) in Other Assets on the Consolidated Balance Sheet. Realized
	    gains and losses on marketable securities are included in other income.

	    iv. Accounts Payable & Distributions Payable to Unitholders

	    Accounts payable and distributions payable to unitholders are classified
	    as other liabilities and are reported at amortized cost. At June 30, 2009
	    the carrying value of these accounts approximated their fair value.

	    v. Long-term debt

	    Bank Credit Facilities

	    The bank credit facilities are classified as other liabilities and are
	    reported at cost. At June 30, 2009 the carrying value of the bank credit
	    facilities approximated their fair value.

	    Senior Unsecured Notes

	    The senior unsecured notes, which are classified as other liabilities,
	    are carried at their amortized cost and translated to Canadian dollars at
	    the period end exchange rate. The following table details the amortized
	    cost of the notes expressed in U.S. and Canadian dollars as well as the
	    fair value expressed in Canadian dollars:

	    Principal Private
	    Placement amount                      Reported CDN $
	    ($thousands)        Amortized Cost    Amortized Cost    CDN $ Fair Value
	    -------------------------------------------------------------------------
	    US $225,000            US $225,000          $261,563            $255,122
	    US $40,000              US $40,000            46,500              45,352
	    CDN $40,000            CDN $40,000            40,000              39,365
	    US $175,000            US $177,305           205,925             203,804
	    US $54,000              US $54,000            62,775              60,959
	    -------------------------------------------------------------------------
	                                                $616,763            $604,602
	    -------------------------------------------------------------------------

	    (b) Fair Value of Derivative Financial Instruments

	    The Fund's derivative financial instruments are classified as held for
	    trading and are reported at fair value with changes in fair value
	    recorded through earnings. The deferred financial assets and credits on
	    the Consolidated Balance Sheets result from recording derivative
	    financial instruments at fair value. At June 30, 2009 a current deferred
	    financial asset of $83,697,000, a current deferred financial credit of
	    $9,985,000, a non-current deferred financial asset of $4,281,000 and a
	    long-term deferred financial credit of $43,636,000 are recorded on the
	    Consolidated Balance Sheet.

	    The deferred financial asset relating to crude oil instruments is
	    $36,080,000 at June 30, 2009 including deferred premiums of $12,154,000.
	    The deferred financial asset relating to natural gas instruments is
	    $47,617,000 at June 30, 2009 including deferred premiums of $10,891,000.

	    The following table summarizes the fair value as at June 30, 2009 and
	    change in fair value for the six months ended June 30, 2009 of the Fund's
	    derivative financial instruments. The fair values indicated below are
	    determined using observable market data including price quotations in
	    active markets.

	                                             Cross
	                                          Currency
	                             Interest     Interest      Foreign
	                                 Rate         Rate     Exchange  Electricity
	    ($ thousands)               Swaps        Swaps        Swaps        Swaps
	    -------------------------------------------------------------------------
	    Deferred financial
	     (credits)/assets,
	     beginning of period  $   (10,051) $   (16,341) $     6,857  $       348
	    Change in fair value
	     asset/(credits)          2,669(1)  (28,193)(2)   (2,576)(3)   (2,053)(4)
	    -------------------------------------------------------------------------
	    Deferred financial
	     (credits)/assets,
	     end of period        $    (7,382) $   (44,534) $     4,281  $    (1,705)
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    Balance sheet
	     classification:
	    Current asset/
	     (liability)          $    (4,286) $    (3,994) $         -  $    (1,705)
	    Non-current asset/
	     (liability)          $    (3,096) $   (40,540) $     4,281  $         -
	    -------------------------------------------------------------------------


	                            Commodity Derivative
	                                Instruments
	                          -------------------------
	    ($ thousands)                 Oil          Gas        Total
	    ------------------------------------------------------------
	    Deferred financial
	     (credits)/assets,
	     beginning of period  $    96,641  $    24,292  $   101,746
	    Change in fair value
	     asset/(credits)       (60,561)(5)    23,325(5)     (67,389)
	    ------------------------------------------------------------
	    Deferred financial
	     (credits)/assets,
	     end of period        $    36,080  $    47,617  $    34,357
	    ------------------------------------------------------------
	    ------------------------------------------------------------

	    Balance sheet
	     classification:
	    Current asset/
	     (liability)          $    36,080  $    47,617  $    73,712
	    Non-current asset/
	     (liability)          $         -  $         -  $   (39,355)
	    ------------------------------------------------------------
	    (1) Recorded in interest expense.
	    (2) Recorded in foreign exchange expense (loss of $2,325) and interest
	        expense (loss of $25,868).
	    (3) Recorded in foreign exchange expense.
	    (4) Recorded in operating expense.
	    (5) Recorded in commodity derivative instruments (see below).

	    The following table summarizes the income statement effects of commodity
	    derivative instruments:

	                        Three months ended June 30, Six months ended June 30,
	    ($ thousands)                2009         2008         2009         2008
	    -------------------------------------------------------------------------
	    Loss due to change
	     in fair value        $   (49,900) $  (160,955) $   (37,235) $  (240,400)
	    Net realized cash
	     gains/(losses)            42,564      (64,060)      88,544      (74,994)
	    -------------------------------------------------------------------------
	    Commodity derivative
	     instruments (loss)/
	     gain                 $    (7,336) $  (225,015) $    51,309  $  (315,394)
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (c) Commodity Risk Management

	    The Fund is exposed to commodity price fluctuations as part of its normal
	    business operations, particularly in relation to its crude oil and
	    natural gas sales. The Fund manages a portion of these risks through a
	    combination of financial derivative and physical delivery sales
	    contracts. The Fund's policy is to enter into commodity contracts
	    considered appropriate to a maximum of 80% of forecasted production
	    volumes net of royalties. The Fund's outstanding commodity derivative
	    contracts as at July 29, 2009 are summarized below.

	    Crude Oil:

	                                                   WTI US$/bbl
	                                   ------------------------------------------
	                                                                       Fixed
	                          Daily    Purc-            Purc-              Price
	                        Volumes    hased     Sold   hased      Sold      and
	                       bbls/day     Call     Call      Put      Put    Swaps
	    -------------------------------------------------------------------------
	    Term July 1, 2009 -
	     December 31, 2009
	      Put                 1,400        -        -  $122.00        -        -
	      Put                 1,000        -        -  $120.00        -        -
	      Put                   500        -        -  $116.00        -        -
	      Put                 1,000        -        -  $ 92.00        -        -
	      Put Spread          1,000        -        -        -   $79.00        -
	      Collar                850        -  $100.00  $ 85.00        -        -
	      3-Way option        1,000        -  $ 85.00  $ 70.00   $57.50        -
	      3-Way option        1,000        -  $ 95.00  $ 79.00   $62.00        -
	      Swap                  500        -        -        -        -  $100.05

	    Jan 1, 2010 -
	     December 31, 2010
	      Purchased Call(1)   1,500   $95.00        -        -        -        -
	      Purchased Call(1)   1,000   $95.00        -        -        -        -
	      Purchased Call(2)   1,000   $90.00        -        -        -        -
	      Purchased Call(2)     500   $90.00        -        -        -        -
	      Purchased Call(2)     500   $92.50        -        -        -        -
	      Swap(1)             1,500        -        -        -        -   $78.45
	      Swap(1)             1,000        -        -        -        -   $78.80
	      Swap(2)             1,000        -        -        -        -   $68.05
	      Swap(2)               500        -        -        -        -   $69.33
	      Swap(2)               500        -        -        -        -   $72.15
	      Swap(2)               500        -        -        -        -   $74.30
	      Swap(2)               500        -        -        -        -   $76.20
	      Swap(2)               500        -        -        -        -   $76.38
	      Put(1)              2,500        -        -        -   $47.50        -

	    -------------------------------------------------------------------------
	    (1) Financial contracts entered into during the second quarter of 2009.
	    (2) Financial contracts entered into subsequent to June 30, 2009.



	    Natural Gas:

	                                                AECO CDN$/Mcf
	                                   ------------------------------------------
	                                                                       Fixed
	                          Daily    Purc-            Purc-              Price
	                        Volumes    hased     Sold   hased      Sold      and
	                       MMcf/day     Call     Call      Put      Put    Swaps
	    -------------------------------------------------------------------------
	    Term
	    July 1, 2009 -
	     October 31,
	     2009
	      Put                  9.5         -        -    $8.44        -        -
	      Put                 14.2         -        -    $7.70        -        -
	      Put                  2.8         -        -    $7.78        -        -
	      Put                  4.7         -        -    $7.87        -        -
	      Put                  4.7         -        -    $7.72        -        -
	      Put Spread           2.8         -        -    $9.23    $7.65        -
	      Put Spread           2.8         -        -    $9.50    $7.91        -
	      Put Spread           5.7         -        -    $9.60    $7.91        -
	      Swap                 3.8         -        -        -        -    $7.86
	    July 1, 2009 -
	     October 31,
	     2010
	      Swap                23.7         -        -        -        -    $7.33
	    November 1, 2009
	     - March 31,
	     2010
	      Put                  4.7         -        -    $8.92        -        -
	      Put                  9.5         -        -    $8.97        -        -
	      Put                  2.8         -        -    $9.07        -        -
	      Put                  4.7         -        -    $9.06        -        -
	      Call                 4.7         -   $12.13        -        -        -
	    2009 - 2010
	      Physical             2.0         -        -        -        -    $2.67
	    -------------------------------------------------------------------------
	    There were no new contracts entered into during or subsequent to the
	    quarter.

	    The following sensitivities show the impact to after-tax net income of
	    the respective changes in forward crude oil and natural gas prices as at
	    June 30, 2009 on the Fund's outstanding commodity derivative contracts at
	    that time with all other variables held constant:

	                                                    Increase/(decrease) to
	                                                     after-tax net income
	                                                 ----------------------------
	                                                  20% decrease  20% increase
	                                                    in forward    in forward
	    ($ thousands)                                       prices        prices
	    -------------------------------------------------------------------------
	    Crude oil derivative contracts                 $    20,208   $   (17,857)
	    Natural gas derivative contracts               $    15,379   $   (14,894)
	    -------------------------------------------------------------------------

	    Electricity:

	    The Fund is subject to electricity price fluctuations and it manages this
	    risk by entering into forward fixed rate electricity derivative contracts
	    on a portion of its electricity requirements. The Fund's outstanding
	    electricity derivative contracts as at July 29, 2009 are summarized
	    below:

	    Term                                    Volumes MWh       Price CDN$/MWh
	    -------------------------------------------------------------------------
	    July 1, 2009 - December 31, 2009                4.0               $74.50
	    July 1, 2009 - December 31, 2009                2.0               $64.00
	    July 1, 2009 - December 31, 2010                4.0               $77.50
	    July 1, 2009 - December 31, 2010                2.0               $68.75
	    January 1, 2010 - December 31, 2011(1)          3.0               $66.00
	    -------------------------------------------------------------------------
	    (1) Electricity contracts entered into during the second quarter of 2009

	    (d) Foreign Exchange:

	    The following sensitivities show the impact to after-tax net income of
	    the respective changes in the period end exchange rate as at June 30,
	    2009, with all other variables held constant:

	                               Increase / (decrease) to after-tax net income
	                               ----------------------------------------------
	                                 25% decrease in $CDN   25% increase in $CDN
	    ($ thousands)                     relative to $US        relative to $US
	    -------------------------------------------------------------------------
	    Translation of US $225 million
	     senior notes                          $  (46,212)             $  46,212
	    Translation of US $40 million
	     senior notes                              (8,215)                 8,215
	    Translation of US $54 million
	     senior notes                             (11,091)                11,091
	    Translation of US$175 million
	     senior notes                             (36,416)                36,416
	    -------------------------------------------------------------------------
	    Total                                  $ (101,934)             $ 101,934
	    -------------------------------------------------------------------------
	    -------------------------------------------------------------------------

	    (e) Interest:

	    The Fund's cash flows are impacted by fluctuations in interest rates as
	    its outstanding bank debt carries floating interest rates and payments
	    made under the CCIRS are based on floating interest rates. To manage a
	    portion of interest rate risk relating to the bank debt, the Fund has
	    entered into interest rate swaps on $120,000,000 of notional debt at
	    rates varying from 3.70% to 4.61% that mature between June 2011 and July
	    2013.

	    If interest rates change by 1%, either lower or higher, on our variable
	    rate debt outstanding at June 30, 2009 with all other variables held
	    constant, the Fund's after-tax net income for a quarter would change by
	    $217,000.

	    Additional Information

	    Additional information relating to Enerplus Resources Fund, including our
	    Annual Information Form, is available under our profile on the SEDAR
	    website at www.sedar.com, on the EDGAR website at www.sec.gov and at
	    www.enerplus.com.

	    For further information regarding this news release or a copy of our 2009
	    second quarter interim report, please contact our investor relations
	    department at 1-800-319-6462 or email investorrelations(at)enerplus.com.
	    >>

	    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.

	    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: the amount, timing and tax treatment
of cash distributions to unitholders; payout ratios and adjusted payout
ratios; tax treatment of income trusts such as the Fund; the structure of the
Fund and its subsidiaries including conversion to a corporate structure; the
Fund's income taxes, tax liabilities and tax pools; the volume and product mix
of the Fund's oil and gas production; production and operational matters
including shut-in wells and delayed projects; oil and natural gas prices and
the Fund's risk management programs; the amount of asset retirement
obligations; future liquidity and financial capacity and resources; future
capital expenditures; cost and expense estimates; results from operations and
financial ratios; the impact of the conversion to IFRS on the financial
results of the Fund; the Fund's ongoing strategy; the Fund's credit exposure;
cash flow sensitivities; royalty rates and their impact on the Fund's
operations and results; future growth including development, exploration, and
acquisition and development activities and related expenditures, including
with respect to both our conventional and oil sands activities. This press
release also contains estimates of contingent resources, 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
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; 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 the Fund's capital and operating requirements as needed; the
continuance of existing and, in certain circumstances, proposed tax and
royalty regimes; the accuracy of the estimates of the Fund's reserve and
resource volumes; and certain commodity price and other cost assumptions. The
Fund 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.
	    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: 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; inaccurate estimation of the Fund's oil and gas reserves and
resources volumes; 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 the MD&A, our MD&A for the year ended December 31,
2008 and in the Fund's Annual Information Form for the year ended December 31,
2008, 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, 2008 filed with the SEC, a copy of which is available 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.

	    INFORMATION REGARDING CONTINGENT RESOURCE ESTIMATES

	    This press 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 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 it will be commercially viable to produce any portion of the
contingent resources or that Enerplus will produce any portion of the volumes
currently classified as contingent resources. For a description of Enerplus'
Kirby oil sands project, including the primary contingencies which currently
prevent the classification of Enerplus' disclosed contingent resources
associated with the Kirby oil sands project as reserves and the inherent risks
and contingencies associated with the resource estimates and development of
the project, see "Presentation of Enerplus' Oil and Gas Reserves, Resources
and Production Information", "Operational Information - Enerplus' Play Types -
Oil Sands" and "Risk Factors" in the Fund's Annual Information Form and Form
40-F as described above.

	    <<
	    Gordon J. Kerr
	    President & Chief Executive Officer
	    Enerplus Resources Fund
	    >>

	    %CIK: 0001126874

	    /For further information: Investor Relations Department at 1-800-319-6462
or email investorrelations(at)enerplus.com/
	    (ERF.UN. ERF)

CO:  Enerplus Resources Fund

CNW 05:55e 10-AUG-09