ENERPLUS ANNOUNCES GUIDANCE FOR 2011 AND OUTLOOK FOR 2012

CALGARY, Dec. 17 /CNW/ -- 
This news release includes forward-looking statements and information
 within the meaning of applicable securities laws. Readers are advised
 to review the "Cautionary Note Regarding Forward-Looking Information
 and Statements" at the conclusion of this news release. For information
 regarding the presentation of certain information in this news release,
 see "Currency, BOE and Operational Information" at the conclusion of
 this news release.


CALGARY, Dec. 17 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX -
 ERF.un, NYSE - ERF) today announced capital spending and operational
 guidance for 2011 and a preliminary outlook for 2012 that is expected
 to result in organic growth in production and reserves.  Throughout the
 past 18 months, Enerplus has captured over 475,000 net acres of
 prospective land primarily in two of the most economic plays in North
 America - the Bakken light oil play and the Marcellus gas play.  In
 addition, the sale of over 10,000 BOE/day of non-core assets as well as
 our Kirby oil sands lease has helped finance our acquisition activities
 and improved our operational focus and profitability. We have a
 foundation of mature, low production decline properties that complement
 our new growth assets that we believe provides a stable platform of
 production and cash flow from operating activities from which to grow.
 We believe our strategy provides a compelling investment opportunity
 comprised of yield and growth. Initially a large portion of our total
 return will be comprised of dividend yield, but as the development of
 our growth plays accelerates, we expect to complement our dividend with
 repeatable annual growth in production and reserves per share.


HIGHLIGHTS:


    --  2011 capital spending is anticipated to increase by over 25% to
        $650 million with 65% projected to be invested in oil projects.
        We expect to focus approximately 85% of our spending on our
        Bakken, Waterflood and Marcellus resource plays. A minimum
        level of capital investment is planned for our natural gas
        assets with the majority directed to our non-operated Marcellus
        interests to further delineate the resource and preserve our
        lease positions.  We also expect a similar level and allocation
        of spending in 2012.

    --  Production is expected to grow by 10% - 15% over the next two
        years, exiting 2012 in the range of 86,000 - 90,000 BOE/day. 
        Crude oil volumes are expected to increase more than 20% over
        the next two years and will represent approximately 48% of
        total volumes by the end of 2012.

    --  In 2011, we expect annual production to average 78,000 - 80,000
        BOE/day, increasing to 80,000 - 84,000 BOE/day by year end.
        Given the longer lead time to production associated with a
        majority of our capital spending in the Marcellus and the
        Bakken, up to 40% of the production associated with our 2011
        drilling program will not come on stream until the remaining
        completion and tie-in capital is expended in 2012.

    --  Light oil production is expected to grow by over 20% as we exit
        2011. Natural gas volumes are expected to remain essentially
        flat throughout the year however we anticipate shallow gas
        production will decline and be replaced by more profitable
        natural gas from the Marcellus.

    --  Based upon the current forward commodity price markets, we
        project cash flow from operating activities ("cash flow") will
        grow by approximately 15% by 2012 as a result of increased
        production, the higher oil weighting in the portfolio and
        higher crude oil prices. Cash flow in 2011 is expected to be
        relatively unchanged from 2010 levels despite selling 10,000
        BOE/day of production throughout 2010. This is mainly a result
        of the increase in crude oil volumes and the increased price
        outlook for crude oil.

    --  We expect rates of return on our oil projects to range from 35%
        to over 100% based on current forward prices.  Returns on our
        natural gas investments, the majority of which are being made
        to delineate and retain land positions, are expected to exceed
        15% in today's natural gas price. We are targeting finding and
        development costs on our oil properties of approximately
        $20/bbl and $2.00/Mcf on our natural gas assets.

    --  Approximately $140 million of our 2011 expenditures are
        expected to be directed to natural gas delineation activities
        in areas such as the Marcellus and the Western Canadian Deep
        Basin. We do not expect this spending to result in meaningful
        production additions in 2011 but will provide valuable insight
        into the viability and opportunity within new play areas.

    --  We intend to continue to distribute a significant portion of
        the cash flow that is generated from our operations and plan to
        maintain our monthly dividend rate of $0.18/share in our
        forecast for the next two years. However, we will continue to
        examine dividend levels as the results of our capital spending
        plans unfold and commodity price.

    --  We expect our capital spending and dividends to exceed our cash
        flow in both 2011 and 2012 however our balance sheet provides
        us with the financial flexibility to support our plans. In
        order to maintain our financial strength beyond 2011, we have
        assumed the sale of non-cash flow generating assets within our
        private equity portfolio or a portion of our non-operated
        working interests in the Marcellus in 2012. Thereafter, our
        debt-to-cash flow levels are expected to decline as production
        from our growth plays accelerates. We have not assumed any
        equity issuance beyond normal dividend reinvestment
        participation in our modeling. We expect our 2011 exit
        debt-to-cash flow ratio to be 1.7 times and 2 times by the end
        of 2012 based upon the current forward commodity markets. 



2011 & 2012 Estimates*


 ____________________________________________________________________
|                                |             2011|             2012|
|________________________________|_________________|_________________|
|Capital Expenditures ($millions)|             $650|             $675|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting         |              65%|              65%|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|
|Annual Average Daily Production:|                 |                 |
|________________________________|_________________|_________________|
|    Oil & Natural Gas Liquids   |  36,000 - 37,500|  39,000 - 41,000|
|(bbls/day)                      |                 |                 |
|________________________________|_________________|_________________|
|    Natural Gas (Mcf/day)       |250,000 - 256,000|260,000 - 265,000|
|________________________________|_________________|_________________|
|    Total (BOE/day)             |  78,000 - 80,000|  83,000 - 85,000|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting         |              47%|              48%|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|
|Exit Production (BOE/day)       |                 |                 |
|________________________________|_________________|_________________|
|     Oil & Natural Gas Liquids  |  39,000 - 41,500|  43,000 - 45,000|
|(bbls/day)                      |                 |                 |
|________________________________|_________________|_________________|
|     Natural Gas (Mcf/day)      |247,000 - 257,000|255,000 - 270,000|
|________________________________|_________________|_________________|
|     Total (BOE/day)            |  80,000 - 84,000|  86,000 - 90,000|
|________________________________|_________________|_________________|
|Exit Change Year-over-Year      |               5%|               8%|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting         |              48%|              50%|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|
|Cash Flow From Operating        |             $700|             $800|
|Activities ($millions)          |                 |                 |
|________________________________|_________________|_________________|
|Oil & Liquids Weighting         |             ~70%|              70%|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|
|Simple Payout Ratio ((1))       |              55%|              50%|
|________________________________|_________________|_________________|
|Adjusted Payout Ratio ((1))     |             150%|             135%|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|
|Debt/Cash Flow at Year-End*     |             1.7x|             2.0x|
|________________________________|_________________|_________________|
|                                |                 |                 |
|________________________________|_________________|_________________|




*Assumptions:
Based upon the forward commodity prices and forecast costs as of
 December 8, 2010 including the impact of hedging.
Based upon our current capital spending plans for Q42010, forecast
 YE2010 debt is approximately $750 million.
(1) Payout ratio is calculated as dividends paid to shareholders divided
 by cash flow from operating activities. Adjusted payout ratio is
 calculated as the sum of dividends paid to shareholders plus
 development capital and office expenditures divided by cash flow from
 operating activities. See "Non-GAAP Measures" below.




2011 and 2012 debt calculations include Marcellus carry commitments of
 $116 million and $66 million respectively.
Monthly dividends held constant at CDN$0.18/share through 2011 and 2012.
Recover in 2012 of $40 million in U.S. tax previously paid.
Assumes $80 million of disposition proceeds in 2012 from equity
 investment portfolio or portion of operated Marcellus interest.


2011 Capital Spending & Production Outlook


We are targeting a capital spending program of $650 million in 2011,
 with approximately 70% of our spending directed to our Bakken and
 Marcellus properties where we expect to see significant growth in
 production and 15% to our waterflood assets where we expect to maintain
 production volumes. We plan to spend over $435 million on development
 drilling, recompletions and facilities, $140 million on delineation
 activities, $29 million on maintenance activities and $44 million on
 seismic.  In total, approximately 113 net wells are planned, two thirds
 of which we would operate and 95% of which would be horizontal wells.


As a result of this spending, we expect annual 2011 production to
 average 78,000 - 80,000 BOE/day, essentially unchanged from exit 2010,
 and to increase to 80,000 - 84,000 BOE/day by year-end.  Oil and
 liquids production is expected to grow 15% by year-end and should
 represent 48% of total volumes at that time.  Shallow gas and other
 conventional oil and gas production is expected to decline throughout
 the year due to reduced capital investment and marginal economic
 returns in the current natural gas price environment.


As a result of our divestment activities in 2010 and our increased focus
 on growth plays in 2011, we expect our decline rate will increase from
 18% to approximately 22% - 23% in 2011. We intend to spend our capital
 budget relatively evenly throughout 2011 and have not assumed any
 material acquisitions or divestments. We will review our 2011 capital
 investment plans regularly throughout the year in the context of
 prevailing economic conditions and potential acquisitions, and make
 adjustments when necessary.  


Key 2011 Capital Spending Plans & Estimated Production





 ____________________________________________________________________
|             |       |     #|2010E Exit|         2011E |            |
|             |Capital|of net|Production|Exit Production|       +/-% |
|Resource Play|  ($MM)| wells|   (BOE/d)|        (BOE/d)|Exit to Exit|
|_____________|_______|______|__________|_______________|____________|
|             |       |      |          |               |            |
|_____________|_______|______|__________|_______________|____________|
|Bakken/Tight |       |    48|    13,000|18,000 - 21,000|          50|
|Oil          |    300|      |          |               |            |
|_____________|_______|______|__________|_______________|____________|
|Waterfloods  |    110|    26|    14,500|13,500 - 15,000|           -|
|_____________|_______|______|__________|_______________|____________|
|Marcellus    |       |    27|     3,000|  7,000 - 8,000|         150|
|Shale Gas    |    160|      |          |               |            |
|_____________|_______|______|__________|_______________|____________|
|             |       |      |          |               |            |
|_____________|_______|______|__________|_______________|____________|
|Resource Play|       |   101|    30,500|38,500 - 44,000|          35|
|Total        |   $570|      |          |               |            |
|_____________|_______|______|__________|_______________|____________|




Crude Oil Investment


Bakken
We expect to direct approximately 65% of our 2011 development spending
 toward oil projects, with the Bakken portfolio attracting $300 million
 of this spending.  The majority of our Bakken activity will be focused
 at Fort Berthold, North Dakota where we hold over 70,000 net acres (110
 sections) of undeveloped land that is prospective for both the Bakken
 and Three Forks formations.


To date in Fort Berthold, we've drilled four short horizontal wells and
 three long horizontal wells into the play targeting the Bakken and
 results have exceeded our expectations.  As we move into the
 development stage, we expect production to grow from 4,000 bbls/day
 currently to over 20,000 BOE/day over the next four years. We are
 currently planning a drilling density at Fort Berthold for the Bakken
 of two short horizontal wells (~4,300 feet with 12 frac stages) per 640
 acre spacing or two long horizontal wells (~9,000 feet with 24 frac
 stages) per 1,280 acre spacing.  Assuming  85% of the land is
 prospective, this would result in 95 - 185 future Bakken horizontal
 drilling locations, depending upon the number of long versus short
 wells.


Based upon current commodity prices and our type curves, we estimate
 short lateral wells have a net present value (before income taxes
 discounted at 12%) of $2.2 million to $5 million and are expected to
 achieve payout in two to three years. Under the same assumptions, long
 horizontal wells would have an estimated net present value of $8.4
 million to $14 million and are expected to achieve payout in less than
 1.7 years.  Given the more attractive economics associated with the
 long lateral wells, we expect that at least 75% of our drilling
 activity will be long lateral wells. The Three Forks formation
 underlies the Bakken throughout our entire acreage position at Fort
 Berthold. We plan to drill a number of Three Forks wells in 2011 to
 evaluate the potential and future prospectivity of this zone.


In 2011, we plan to have three to four rigs working in the play and
 expect to drill approximately 32 net operated wells (~90% working
 interest) and participate in another two net non-operated wells.  We
 recently entered into agreements to secure rigs and access to frac
 services and proppant which will help to ensure the timely execution of
 our plans. We also expect to have mid-stream arrangements in place by
 the middle of 2011 which will allow us to capture the associated
 natural gas volumes. Due to the high initial production rates
 associated with these wells, it will be challenging to predict exit
 production rates. As such, exit rates may vary considerably based upon
 when new wells come on stream.


 _____________________________________________________________________
|             |                     Fort Berthold Bakken Wells        |
|_____________|_______________________________________________________|
|             |    Type Curve Estimate  |     Actual Results to Date  |
|_____________|_________________________|_____________________________|
|             |             |   Average |Long Laterals |Short Laterals|
|             |  Average    |    Short  |   (2 well    |   (4 well    |
|             |Long Laterals|  Laterals |   average)   |   average)   |
|_____________|_____________|___________|______________|______________|
|             |             |           |              |              |
|_____________|_____________|___________|______________|______________|
|Average 30   |             |           |              |              |
|Day Initial  |1,100 - 1,200|  550 - 650|              |              |
|Production   |     bbls/day|   bbls/day|1,190 bbls/day|  800 bbls/day|
|_____________|_____________|___________|______________|______________|
|Expected     |             |           |              |              |
|Ultimate     |    600 - 800|  300 - 400|              |              |
|Recovery     |        Mbbls|      Mbbls|              |              |
|_____________|_____________|___________|______________|______________|
|Cost/Well    |   $8 million| $6 million|    $8 million|    $6 million|
|_____________|_____________|___________|______________|______________|
|120 Day      |             |           |              |              |
|Cumulative   |             |           |              |              |
|Production ( |             |           |              |              |
|(1))         |     81 Mbbls|   40 Mbbls|     108 Mbbls|      59 Mbbls|
|_____________|_____________|___________|______________|______________|
|             |             |           |              |              |
|_____________|_____________|___________|______________|______________|
|Net Present  |             |           |              |              |
|Value (      | $8.4 - $14.0|$2.2 - $5.0|              |              |
|(2))/well    |      million|    million|              |              |
|_____________|_____________|___________|______________|______________|
|Netback ((3))|     ~$48/bbl|   ~$48/bbl|              |              |
|_____________|_____________|___________|______________|______________|
|Payout Period|     1 to 1.7|   2 to 3.0|              |              |
|(years)      |        years|      years|              |              |
|_____________|_____________|___________|______________|______________|




(1) Net present value before income taxes discounted at 12% using
 forward commodity price assumptions at December 8, 2010
(2) Only 2 long lateral wells have been on production for 120 days.
 Average 30 day initial production rates for 3 long lateral wells is
 1,175 bbls/day
(3) Netback is used to measure operating performance and is calculated
 by subtracting Enerplus' expected royalties and operating costs from
 the anticipated revenues in respect of the relevant properties. See
 "Non-GAAP Measures" below.


In our other Bakken prospects, six gross wells (four net) expected to be
 drilled at Sleeping Giant in Montana, three of which will be long
 laterals. We continue to evaluate options regarding enhanced oil
 recovery opportunities as the number of drilling locations remaining
 within this property becomes limited. At Oungre, Saskatchewan, we are
 currently evaluating the results of two horizontal wells recently
 completed. We are also currently shooting seismic to further evaluate
 the Bakken and Ratcliffe potential in the Freda/Neptune/Oungre area. 


As a result of our capital spending across our entire Bakken/tight oil
 resource play in 2011, we expect production volumes will grow by 50%,
 exiting the year in the range of 18,000 - 20,000 BOE/day.


Waterfloods
Our waterflood portfolio is comprised of a variety of crude oil
 properties in various plays, such as the Glauconitic, Viking, Cardium,
 and Ratcliffe.  These mature assets have significant amounts of
 original oil in place ("OOIP") with recovery to date of approximately
 22%.  The average quality of oil in these play areas is approximately
 30 degree API. Our plans for 2011 include drilling production and
 injection wells at our Medicine Hat, Freda Ratcliffe, Gleneath and
 Pembina 5-Way properties to increase oil production and maintain and/or
 improve reservoir pressures. In addition, we expect to invest in
 facility improvements to support future development plans and plan to
 continue work on two polymer pilots at Giltedge and Medicine Hat to
 increase ultimate recoveries.  The base production decline rate from
 these properties is approximately 16%. We plan to invest over $100
 million, maintaining production volumes throughout the year at
 approximately 14,000 BOE/day.  A significant portion of this capital is
 being directed to activities that we believe will position us for
 future production and reserve growth.


Our waterflood properties are an important part of our future strategy
 as they generate a significant amount of free cash flow (cash flow
 after capital expenditures) to support our dividend and growth
 strategy.  At December 31, 2009, we had 77 million BOE of proved plus
 probable reserves booked to our waterfloods, representing an estimated
 recovery factor of 27%. We believe that through continued drilling and
 optimization as well as the application of enhanced oil recovery
 schemes, we could improve the ultimate recovery of oil from these pools
 to between 30% and 37%. This could add 50 - 150 million barrels of
 crude oil and associated natural gas to Enerplus' booked reserves.


Natural Gas Investment


With the current natural gas price outlook we plan to minimize our
 spending on our natural gas assets in 2011. Our efforts will be focused
 on delineating lease positions in new areas.  Approximately $230
 million is expected to be invested into our natural gas assets in 2011,
 $160 million of which is planned for our Marcellus interests. The
 majority of the remainder of our natural gas spending is planned in the
 Deep Basin area where we hold over 65,000 net acres of undeveloped
 land.  We plan to drill four delineation wells targeting the Stacked
 Mannville in the South Ansell area where other producers have had
 recent success.  Our shallow gas activities will consist of
 recompletion activities at Shackleton. As a result of the decrease in
 spending in our tight and shallow gas resource plays, we expect
 production volumes from these plays will decline throughout 2011.


Marcellus
Approximately $160 million is planned for the Marcellus, the majority of
 which is anticipated to be spent on our non-operated interests.  With
 our joint venture partner, we plan to have eight to ten rigs working
 throughout the play in 2011 and expect to drill 150 gross wells (22.4
 net).  We also expect to complete approximately 121 wells and we plan
 to have 94 new wells on stream by the end of the year.  Due to the
 timing of infrastructure, accessing frac crews and permitting, the
 estimated cycle time from commencement of drilling to production tie-in
 is approximately nine months. As a result of this timeframe, close to
 75% of the wells that we plan to drill in 2011 will not be tied-in
 until 2012.  Production in 2011 is expected to grow by 150% to 45
 MMcf/day by year-end. There are currently 42 gross wells on stream
 producing approximately 100 MMcf/day gross of natural gas. A further 45
 MMcf/day of production is currently awaiting infrastructure, completion
 or tie-in. 


Well results over the past 18 months have either met or exceeded our
 expectations. Cumulative production on eight wells that have been on
 production for six months have ranged from 450 MMcf to 1.5 Bcf of
 natural gas per well with average 180 day cumulative production of 785
 MMcf.  We have increased our type curve expectations in the Marcellus
 from 3.0 - 3.5 Bcf/well originally to 3.5 - 6.0 Bcf/well.  Well costs
 have also increased due to the drilling of longer lateral lengths with
 more frac stages.  In 2011 we estimate average well costs to range from
 $4.5 million to $6.0 million per well based upon drilling 3,500 - 5,000
 foot lateral lengths with 8 - 12 frac stages. As a greater percentage
 of our drilling program moves into the development stage, we would
 expect well costs to decrease due to established water infrastructure
 and pad drilling.


The table below illustrates the economics associated with a range of
 type wells under different natural gas price scenarios.  We have
 assumed a $6 million cost per well under each scenario.


Marcellus Dry Gas Economics


 ________________________________________________________________
|       |    4.0 Bcf well  |    5.0 Bcf well  |    6.0 Bcf well  |
|_______|__________________|__________________|__________________|
| NYMEX |   |Payout|NPV 12%|   |Payout|NPV 12%|   |Payout|NPV 12%|
|$/MMbtu|IRR|years | ($MM) |IRR|years | ($MM) |IRR|years | ($MM) |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $6.00 |27%|  3.4 | $2.51 |41%|  2.5 | $4.57 |57%|  2.0 | $6.62 |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $5.00 |16%|  4.9 | $0.75 |26%|  3.4 | $2.37 |37%|  2.6 | $3.99 |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $4.00 |7% |  8.6 |($1.02)|13%|  5.7 | $0.17 |20%|  4.2 | $1.35 |
|_______|___|______|_______|___|______|_______|___|______|_______|




We expect approximately 25% of our spending in 2011 will be focused on
 drilling in the liquids rich area of southwest Pennsylvania and
 northern West Virginia where the associated natural gas liquids provide
 better economics and the well costs are closer to $5 million.  This
 improves the internal rate of return on a typical 4.0 Bcf well from 7%
 to 21% in a $4 NYMEX gas price environment and improves the net present
 value before income taxes discounted at 12% from -$1.02 million to
 $1.34 million. These liquids rich wells are expected to have a
 breakeven supply cost of approximately $3.70/Mcf.  Approximately 30% of
 our spending is expected to be directed to delineation activity to
 preserve our lease positions and identify future potential.  We plan to
 spend the remaining 45% of our capital budget on development drilling
 in counties where we expect ultimate recoveries in the 4.5 - 5.5 Bcf
 range.


We also expect to drill five gross operated delineation wells (4 net) on
 our new Marcellus leases in 2011.


Costs
As a result of the sale of non-core, lower margin properties, operating
 costs in 2010 have decreased by 6% to approximately $10.20/BOE from our
 original guidance of $10.90/BOE.  We expect to see a further reduction
 in operating costs in 2011 to approximately $9.20/BOE due to a full
 year impact of the dispositions and the addition of lower cost
 production associated with our Bakken and Marcellus plays. 


In order to improve our operational effectiveness, Enerplus has been
 actively working to improve not only our underlying asset base, but
 also our internal technical capabilities.  We have increased our
 staffing levels within our U.S. operations by 50% in order to
 effectively manage our growing portfolio in the Bakken and the
 Marcellus and have also increased our technical capabilities within our
 Canadian operations. These changes have resulted in an increase in our
 general and administrative costs ("G&A"). The adoption of International
 Financial Reporting Standards ("IFRS") will also impact our G&A
 expenses going forward. Previously staff costs associated with our
 acquisition and divestment activities were capitalized however under
 IFRS, these costs will now be expensed. They are expected to contribute
 approximately $0.20/BOE of incremental cost to our G&A expense.  As a
 result of these changes and lower annual average production volumes
 expected in 2011 due to asset sales in 2010, we expect G&A costs will
 average approximately $3.30/BOE for the year.  As our capital plans are
 executed and production volumes increase throughout 2011 and into 2012,
 we expect to see a reduction in per BOE G&A expenses.


In the context of current forward commodity prices, we expect Crown and
 freehold royalties to be approximately 20% of our gross oil and gas
 sales in 2011 up from 18% in 2010 due to the increase in oil weighting
 within our portfolio and a stronger outlook for oil prices in 2011
 compared to 2010.


Taxes
Enerplus has received Unitholder and court approval to convert to a
 corporation effective January 1, 2011. As such, we will be subject to
 taxation at the same level as other Canadian corporations. Enerplus
 currently has approximately $3 billion in tax pools that we plan to
 utilize to meet our tax obligations in Canada and therefore do not
 expect to pay cash taxes in Canada for three to five years.  As a
 result of the higher capital spending in our U.S. operations, we expect
 cash taxes in the U.S. will be less than 5% of U.S. cash flow in 2011.


Hedging
Our hedging program is designed to protect a portion of our cash flow to
 support our capital spending plans, the economics of our acquisitions
 and the dividend component of our business model.  Typically we will
 hedge forward with a view to providing downside protection in the event
 commodity prices fall while attempting to maintain some of the upside
 of future price improvements. Based upon the current forward market,
 Enerplus has floor protection on approximately 56% of our forecast 2011
 crude oil production net of royalties at an effective price of
 US$87.10/bbl. For the first quarter of 2011, we have approximately 32%
 of our projected 2011 natural gas production volumes, net of royalties,
 hedged at an effective price of $6.14/Mcf. For 2012, we have
 approximately 7% of our projected crude oil production net of royalties
 hedged at an effective price of $90.29/bbl.  We expect to continue our
 price risk management program by adding to our crude oil hedge
 positions however we are reluctant to hedge any significant natural gas
 volumes in the current low price environment.


Acquisitions & Divestments
As part of our on-going business, we expect to acquire additional assets
 in key areas that fit with our business strategies and also divest of
 assets that are no longer part of our future plans. We do not have any
 specific plans to package and sell any significant producing non-core
 properties in 2011. As previously stated we expect to sell non-cash
 flow generating assets from our portfolio of equity investments or sell
 part of our non-operated Marcellus interests in 2012 in order to
 preserve our financial flexibility.  As part of our original
 acquisition agreement, we expect to spend $116 million on our capital
 carry commitments associated with the Marcellus in 2011.


Outlook
We are positioning Enerplus to deliver competitive long-term returns
 that include a balance between growth and income to investors. We've
 made significant strides in repositioning our asset base and now have
 meaningful growth opportunities in our portfolio. We also have a strong
 foundation of mature, cash generating assets that can support our
 growth and income strategy.  We have maintained our financial
 flexibility throughout the past 18 months and our strong balance sheet
 will assist us in executing our strategy. Initially, a large portion of
 our total return will be comprised of dividend yield but as the
 development of our growth plays accelerates, we expect to supplement
 our dividend with sustainable growth in production and reserves per
 share.


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


Currency, BOE and Operational Information


All dollar amounts or references to "$" in this news release are in
 Canadian dollars unless specified otherwise.  Enerplus has adopted the
 standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may
 be misleading, particularly if used in isolation. A BOE conversion
 ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion
 method primarily applicable at the burner tip and does not represent a
 value equivalency at the wellhead. Unless otherwise stated, all oil and
 gas production information and estimates are presented on a gross
 basis, before deducting royalty interests.


Cautionary Note Regarding Forward-Looking Information and Statements


This news release contains certain forward-looking information and
 statements within the meaning of applicable securities laws. The use of
 any of the words "expect", "anticipate", "continue", "estimate",
 "budget", "guidance", "objective", "ongoing", "may", "will", "project",
 "should", "believe", "plans", "intends", "strategy" and similar
 expressions are intended to identify forward-looking information or
 statements. In particular, but without limiting the foregoing, this
 news release contains forward-looking information and statements
 pertaining to the following: future capital spending amounts (including
 capital carry commitments), the timing thereof and the types of
 projects on which such capital will be spent; future growth
 opportunities; future oil, natural gas liquids and natural gas
 production levels, the product mix of such production and production
 decline rates; future cash flow levels; rates of return on our
 expenditures, investments and projects; the expected ultimate recovery
 of oil or gas from a particular well; finding and development costs,
 operating costs, general and administrative expenses and royalty
 expenses; sales of our equity portfolio and our non-operated working
 interests in the Marcellus play and the redeployment of proceeds
 realized there from; dividend payments made by Enerplus and the related
 payout and adjusted payout ratios; returns to our securityholders; debt
 levels and debt to cash flow ratios; drilling plans and results,
 including production rates, recovery factors, the cost, netback and net
 present value per well and well payout periods; the potential impact of
 IFRS on our financial and operating results; our conversion from an
 income trust to a corporation and the timing and payment of future
 taxes as a result; our planned commodity risk management program; and
 future liquidity, debt levels and financial capacity and resources. 


The forward-looking information and statements contained in this news
 release reflect several material factors and expectations and
 assumptions of Enerplus including, without limitation: that Enerplus
 will achieve operational, production and drilling results as
 anticipated; the general continuance of current or, where applicable,
 assumed industry conditions; commodity prices will remain within
 Enerplus' expected range of forecast prices; availability of adequate
 cash flow, debt and/or equity sources to fund Enerplus' capital and
 operating requirements as needed and to pay dividends to shareholders
 as anticipated; the continuance of existing and, in certain
 circumstances, proposed tax and royalty regimes; availability of
 willing buyers for the properties proposed to be disposed of; that
 capital, operating and financing costs will not exceed Enerplus'
 current expectations; availability of third party service providers
 (including drilling rigs and service crews) and cooperation of industry
 partners; and certain foreign exchange rate and other cost assumptions.
 Enerplus believes the material factors, expectations and assumptions
 reflected in the forward-looking information and statements are
 reasonable at this time but no assurance can be given that these
 factors, expectations and assumptions will prove to be correct.  


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 or
 drilling results or production declines; changes in tax or
 environmental laws or royalty rates; failure to receive required third
 party approvals; increased debt levels or debt service requirements;
 insufficient available cash to pay dividends as currently anticipated;
 inaccurate estimation of or changes to estimates of Enerplus' oil and
 gas reserves and resources volumes and the assumptions relating
 thereto; limited, unfavourable or no access to debt or equity capital
 markets; increased costs and expenses; a shortage of third party
 service providers; the impact of competitors; reliance on industry
 partners; an inability to agree to terms with potential buyers of
 assets that may be disposed of; and certain other risks detailed from
 time to time in Enerplus' public disclosure documents including,
 without limitation, those risks identified in our MD&A for the year
 ended December 31, 2009 and in Enerplus'  Annual Information Form dated
 March 13, 2010 for the year ended December 31, 2009, copies of which
 are available on Enerplus' SEDAR profile at www.sedar.com and which also form part of Enerplus' annual report on Form 40-F for
 the year ended December 31, 2009 filed with the United States
 Securities and Exchange Commission, 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 news release, and Enerplus
 assumes no obligation to publicly update or revise them to reflect new
 events or circumstances, except as may be required pursuant to
 applicable laws.


Non-GAAP Measures


Throughout this news release we use the term "payout ratio" and
 "adjusted payout ratio" to measure operating performance, leverage and
 liquidity. We calculate payout ratio by dividing dividends paid to
 shareholders by cash flow. "Adjusted payout ratio" is calculated as
 dividends paid to shareholders 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.


Netback is used to measure operating performance and is calculated by
 subtracting Enerplus' expected royalties and operating costs from the
 anticipated revenues in respect of the relevant properties. The term
 "netback" does 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.



To view this news release in HTML formatting, please use the following URL: http://www.newswire.ca/en/releases/archive/December2010/17/c6102.html



pplease contact our Investor Relations Department at 1-800-319-6462 or  email a href="mailto:[e-mail]" cr="true"[e-mail]/a/p

Copyright