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Enerplus announces operational guidance for 2010 and preliminary 2009 year-end reserve and resource information

December 14, 2009

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. 14 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) today announced capital spending and operational guidance for 2010 as well as preliminary reserve and resource information for year-end 2009.

We are positioning Enerplus to deliver competitive long-term returns that include a balance between growth and income to investors. Our 2010 development capital program and operating guidance reflects compelling economic returns from our investments into existing assets while also investing in organic early stage growth opportunities. We intend to continue adding quality assets in both Canada and the U.S. that provide significant future growth potential and attractive operating metrics. We are also planning on selling assets that do not fit our strategy to focus our organization on fewer high impact resource plays. Our preliminary contingent resource estimates for year-end 2009 reflect the success we have had to date in transitioning our asset base and show meaningful growth in the upside associated with the Marcellus shale gas play and our oil sands. Our preliminary reserve information highlights negative revisions tied in part to a more compelling opportunity set outside of our historical assets and a more challenged investment environment for natural gas drilling projects in North America.


Capital Development Spending


We are forecasting 2010 capital development spending of $425 million compared to our 2009 expected expenditures of $315 million ($330 million with carry commitments). We are forecasting a 35% increase in development capital spending in 2010 given the improvement in crude oil prices and economic conditions, the strength of our balance sheet and increased opportunities associated with early stage growth-oriented assets.

In comparison with last year, this increase in capital spending is primarily related to new opportunities in the Bakken oil resource play and the Marcellus shale gas play. We anticipate that approximately $260 million of our 2010 budget will be spent on our Canadian assets and $165 million on our U.S. operations. We currently expect approximately 56% of our spending will be directed at oil opportunities with the remainder on natural gas opportunities. We plan to direct our oil activities primarily at our Bakken properties in Canada and the U.S., as well as waterflood and conventional oil projects in western Canada. Our natural gas spending plans are primarily concentrated in the Marcellus shale gas play, drilling in the Canadian deep basin and shallow gas drilling in Alberta that is supported by government incentives. We expect our 2010 projects to provide compelling economic returns at WTI prices of US$60/bbl, AECO natural gas prices of C$4.20/Mcf and NYMEX gas prices of US$4.50/Mcf.

Our capital spending plans include approximately $125 million on pilot well drilling, seismic and minor land purchases associated with existing properties. Our guidance does not include any acquisition activity or large undeveloped land purchases as these are opportunistic and difficult to predict.

We will review our 2010 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments as deemed necessary. We anticipate our spending will be evenly distributed throughout the year given the nature and location of our spending.


    Projected 2010 Capital Expenditures

                                         Spending*    Number of net wells
    Resource Play                       ($ millions)          to be drilled

    Bakken/Tight Oil                           $118                      42
    Waterfloods                                  92                      38
    Other Conventional Oil                       27                       7
    Total Oil                                  $237                      87

    Marcellus Shale Gas                         $80                      11
    Tight Gas                                    49                       5
    Shallow Gas                                  38                     156
    Other Conventional Gas                       21                      10
    Total Gas                                  $188                     182

    Company Total                              $425                     269

    % crude oil                                 56%                     32%

    * Capital spending total is after the recovery of $33 million of
        Alberta drilling royalty credits; includes drilling, facilities,
        maintenance and capitalized G&A


Production Guidance


Based upon our capital spending plans for 2010, we expect to produce on average approximately 37,000 bbls/day of crude oil and natural gas liquids and 294 MMcf/day of natural gas, totaling approximately 86,000 BOE/day, down roughly 2% from our anticipated 2009 exit rate of approximately 88,000 BOE/day. Crude oil and natural gas liquids production is expected to increase throughout 2010 and represent approximately 45% of our exit rate volumes. As the results of our development programs are realized, we expect our exit production rate will increase back to our anticipated 2009 exit rate levels of approximately 88,000 BOE/day setting the stage for continued growth in 2011. Our production forecast does not reflect any acquisition or divestment activities in 2010.


    Projected 2010 Average Annual Production

                           Crude   Natural Gas
    Resource                 oil       Liquids    Natural Gas          Total
    Play               (bbls/day)    (bbls/day)     (MMcf/day)      (BOE/day)
    Bakken/Tight Oil       9,900             -            8.4         11,300
    Waterfloods           13,400           500            9.0         15,400
    Marcellus Shale Gas        -             -           10.8          1,800
    Tight Gas                  -         1,700           67.8         13,000
    Shallow Gas                -             -          114.6         19,100
    Conventional Oil
     & Gas                 9,700         1,800           83.4         25,400

    Company Total         33,000         4,000            294         86,000

    % of Total                38%            5%            57%

    Projected 2010 Exit Rate Production

                           Crude   Natural Gas
    Resource                 oil       Liquids    Natural Gas          Total
    Play               (bbls/day)    (bbls/day)     (MMcf/day)      (BOE/day)
    Bakken/Tight Oil      10,900             -            8.4         12,300
    Waterfloods           14,400           500            9.0         16,400
    Marcellus Shale Gas        -             -           18.0          3,000
    Tight Gas                  -         1,700           69.0         13,200
    Shallow Gas                -             -          109.2         18,200
    Conventional Oil
     & Gas                 9,700         1,800           80.4         24,900

    Company Total         35,000         4,000            294         88,000

    % of Total                40%            5%            55%


Operating Costs


We expect operating costs to be approximately $340 million, averaging $10.90/BOE in 2010. We are anticipating a modest increase in our power and labour costs, but expect other operating costs to stay essentially flat. These increases combined with the declining average production anticipated in 2010 causes operating costs per BOE to increase 7% from our current 2009 forecast of $10.20/BOE.


General & Administrative Costs and Conversion Costs


G&A costs are expected to average $2.45 per BOE in 2010 which is in line with our 2009 expectations despite declining average production. Included in our 2010 G&A forecast are non-cash G&A costs of approximately $0.20/BOE. We are expecting to reduce costs in Canada; however these cost savings are anticipated to be offset somewhat by increasing U.S. costs as we enhance our capabilities in the Marcellus shale gas play and in the North Dakota Bakken oil play.

In addition, we are expecting an incremental $3 million or $0.10/BOE in costs associated with conversion from a trust to a corporation. In response to the Canadian government's tax on trusts set to come into effect on January 1, 2011, we plan on amalgamating most of our underlying operating entities and filing a Plan of Arrangement to effect a corporate conversion effective January 1, 2011. A unitholder vote is anticipated in late 2010. We intend to report conversion costs separately throughout 2010.


Royalties & Taxes


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 2010, which is slightly higher than our 2009 expectations of 17%. In addition, we expect cash taxes to be less than 5% of our U.S. cash flow in 2010. We do not expect to pay any significant Canadian taxes.




Based upon the current forward market, Enerplus has floor protection on approximately 34% of our forecast 2010 crude oil production net of royalties at an effective price of approximately US$77 per barrel. With regard to natural gas, we currently have approximately 17% of our projected 2010 natural gas production volumes, net of royalties, hedged at an effective price of $6.80 per Mcf. We expect to continue our price risk management program in 2010 dependent on commodity prices, our financial position, and our plans with respect to capital spending and acquisitions.




As part of our strategy to improve our performance and introduce more early stage growth opportunities to our portfolio, we expect to continue to pursue acquisitions in tight oil and tight gas resource plays. We currently have our entire $1.4 billion credit facility available to support this strategy.

We expect to spend approximately $64 million (US$61 million) on our capital carry commitments associated with our Marcellus shale gas acquisition and approximately $11 million (US$10.5 million) in capital carry commitments associated with our North Dakota Bakken oil acquisition. Capital carry commitments are considered to be part of the original cost of acquisition and will be reported as such when they are incurred and are not included in our development capital spending guidance.




As part of our strategy to improve the profitability and focus within our portfolio, we plan to divest of various non-core properties that do not fit with our resource play focus. These properties are located primarily within western Canada and currently produce approximately 14,000 BOE/day with a 60% weighting to crude oil and associated liquids. Given the uncertainty around the timing of any dispositions, we have not adjusted our 2010 production guidance for this divestment activity. However, we would expect to sell a portion of this non-core portfolio in 2010 and realize proceeds of at least $200 million which we would target for redeployment into new acquisitions.


Kirby Oil Sands


We continue to expect regulatory approval of our 10,000 BOE/day Kirby in-situ oil sands project in early 2010. While we believe that there is value in the Kirby project, the anticipated return on investment and timing of positive cash flow is currently not compelling relative to our existing portfolio of opportunities. As a result, our 2010 capital budget includes minimal spending associated with this lease. We continue to believe in the quality and potential of Kirby and our independent reserve engineers have increased the best estimate of contingent resources by more than 100% to approximately 500 million barrels of bitumen since acquiring Kirby in early 2007. See "Information Regarding Contingent Resource Estimates" at the end of this news release. We will be reviewing our long-term plans as they relate to Kirby in 2010.


Financial Strength


Enerplus has one of the strongest balance sheets within the oil and gas sector with a trailing 12 month debt to cash flow ratio of 0.7 times at September 30, 2009. At November 30, 2009 we had approximately $560 million of long-term debt comprised solely of senior unsecured notes and our entire $1.4 billion credit facility is currently unutilized. We are forecasting year-end 2009 debt of approximately $600 million.

We expect that our debt levels may increase by approximately $150 million by the end of 2010 to 1.0 times debt-to-cash flow in the context of our 2010 capital budget and carry commitments if current forward prices prevail (WTI US$81.65/bbl and AECO gas $5.63/Mcf), distribution levels remain constant and disregarding potential acquisitions or divestments.

Given our focus on early stage resource plays such as the Marcellus and Bakken, we will consider investment and distribution levels that modestly exceed cash flow provided we retain balance sheet strength and achieve compelling economics on our development capital program.


Preliminary 2009 Year-End Contingent Resource and Reserves Outlook


In August of 2009, Enerplus advised that McDaniel & Associates Consultants Ltd. ("McDaniel") was replacing Sproule Associates Ltd. as our independent reserve evaluator for all our Canadian conventional assets. GLJ Petroleum Consultants Ltd. ("GLJ") will continue to evaluate our oil sands assets, Netherland Sewell & Associates Inc. ("NSAI") will continue to evaluate our western U.S. assets and Haas Petroleum Engineering Services Inc. ("Haas"), established oil and gas reserve evaluators located in Dallas, have been retained to evaluate our Marcellus shale gas assets.

We expect a material increase in the contingent resources for the company from both the acquisition in the Marcellus shale gas play and on oil sands as compared to year-end 2008. Haas has completed a preliminary contingent resource estimate on the Marcellus and GLJ has completed their draft contingent resource report on our Kirby oil sands property. Both of these estimates have been conducted in accordance with National Instrument 51-101. For additional information on disclosure of contingent resource estimates, see "Information Regarding Contingent Resource Estimates" at the end of this news release.

Based on the draft GLJ report, the Kirby oil sands best estimate of contingent resources has increased from 417 million barrels of bitumen at year-end 2008 to 497 million barrels of bitumen at year-end 2009 which reflects a 19% increase year-over-year and a 104% increase since acquiring the lease in 2007.

Based on the preliminary Haas report, we expect the best estimate of contingent resources in our Marcellus acreage to increase 0.7 trillion cubic feet ("Tcf") from an internal estimate of 1.4 Tcf of natural gas effective July 1, 2009 and reported at the time of the acquisition to approximately 2.1 Tcf at year-end 2009. This increase is based on area results which support higher type curve recoveries and higher well density and overall recoveries per section. We continue to assume the land utilization is 55% as per our original estimate and that the average type well recoveries may increase from an average of 3.2 billion cubic feet ("Bcf") per well to approximately 3.4 Bcf per well with the higher prospective areas showing approximately 5 Bcf per well. We also expect aggregate by section recoveries to increase from 12-20% to approximately 30% with an average of 4-8 wells per section versus 4-6 wells per section in the original analysis. The Marcellus play continues to be in its early days, but our results and industry results are supporting higher expectations of type well and section recoveries. In addition, we continue to see upside in the amount of land that could be developed over time as delineation results continue to come in.

We expect to book only a modest amount of reserves associated with our Marcellus properties at year-end 2009 given the limited number of wells and limited time these wells have been on production. We do, however, continue to see upside as reflected in the contingent resource estimate and would expect to see F&D costs, FD&A costs and recycle ratios improve corporately over time with success in this and other plays within the company.

Based upon discussions with NSAI to date, we do not expect any material revisions to our U.S. reserves and we continue to expect positive additions associated with the on-going development of these assets.

Preliminary estimates from McDaniel, combined with an internal assessment of our minor properties, have indicated a decrease of approximately 0.36 Tcf of natural gas reserves and 6.5 MMbbl of crude oil reserves representing approximately 24% of our natural gas reserves and approximately 4% of our crude oil reserves on a proved plus probable basis at year-end 2008. These revisions are due to changes in evaluation methodology, the removal of undeveloped drilling locations, reservoir performance and the decline in natural gas prices all of which are primarily associated with our shallow natural gas assets. We expect a final report early in 2010 and will include this information in our year-end results which we anticipate announcing in late February 2010. The final report may include possible changes associated with year-end pricing however, we do not expect these revisions to change materially. We expect that the final report will also include reserve additions based on our 2009 capital program which are not reflected in the revisions noted above.

From a methodology standpoint, McDaniel has made a different assessment of final producing rates and decline factors than previously used which has resulted in a significant impact primarily on our shallow gas reserves.

We expect to remove approximately half of the undeveloped drilling locations from our year-end reserves estimates, the majority of which are shallow gas. This relates in part to our plans to direct less capital to these assets in the future as we now have better opportunities elsewhere in our portfolio as well as the decline in gas prices which has made a number of drilling locations uneconomic. Reservoir performance issues associated with our shallow natural gas properties have also reduced the number of drilling locations and associated reserve volumes although we expect to continue drilling approximately 200 shallow gas wells per year subject to gas prices and portfolio changes. We expect to have in the order of six years of drilling inventory after adjustments at year-end 2009.

The performance shortfall is related primarily to shallow gas performance associated with increased interference and poorer infill well performance. This poorer performance has steepened the decline of our shallow gas properties yet it has not had a material impact on our current year production and we continue to see overall corporate production performance that remains in line with our expectations. We have also incorporated this decline in performance into our 2010 production guidance.

We expect our overall 2009 corporate finding & development ("F&D") costs, finding, development & acquisition ("FD&A") costs and recycle ratios to be negatively impacted by the revisions noted above. While this will also impact our net asset value, we believe that the impact may be less on a proportional basis given the declines are largely attributable to natural gas properties and the later life impact of some of the reserve changes.




Enerplus is well positioned to execute on our growth and income-oriented business strategy. We are focused on activities that we expect will improve our operational performance and deliver value through growth and distributions. We are executing on our strategies relative to early stage participation in resource growth plays such as the Marcellus and expansion of our Bakken and Deep Basin interests. When combined with our continued financial strength, we are setting the stage for success going forward.


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. Where applicable, Canadian dollar amounts have been converted to U.S. dollars using an exchange rate of CDN$1.00 = US$1.06. The actual U.S. dollar equivalent may be greater or less than the amount presented based on the exchange rate in effect at the applicable times.

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; increased opportunities associated with growth assets; returns on our expenditures and investments; future oil and natural gas prices and foreign exchange rates; future acquisitions and dispositions and the costs and proceeds realized therefrom; drilling activities; the volume and product mix of our oil and natural gas production; the development of our oil sands project (including receipt of regulatory approvals); reserve and contingent resource estimate and the assumptions relating thereto, including land development and well densities and production; future operating, general and administrative and trust conversion costs and other expense estimates; F&D costs, FD&A costs and recycle ratios; royalties and taxes payable; our commodity risk management programs; future liquidity, debt levels and financial capacity and resources; future cash distributions to our unitholders; corporate structure and conversion to a corporate form and the timing thereof; and future growth opportunities including development, exploration, and acquisition activities and related expenditures.

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 conduct its operations, and will achieve operational results, as anticipated; the general continuance of current or, where applicable, assumed industry conditions; continuation of improved commodity prices; availability of cash flow, debt and/or equity sources to fund the Fund's capital and operating requirements as needed and to pay distributions to unitholders; 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; well density and production rates and land development; and certain commodity price, foreign exchange rate 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; failure to receive required third party approvals; increased debt levels or debt service requirements; inaccurate estimation of or changes to estimates of the Fund's 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; the impact of competitors; reliance on industry partners; factors that may lead to an early conversion to a corporate structure; and certain other risks detailed from time to time in the Fund's public disclosure documents including, without limitation, those risks identified in our MD&A for the year ended December 31, 2008 and in the Fund's Annual Information Form dated March 13, 2009 for the year ended December 31, 2008, copies of which are available on the Fund's SEDAR profile at and which also form part of the Fund's annual report on Form 40-F for the year ended December 31, 2008 filed with the United States Securities and Exchange Commission, a copy of which is available at

The forward-looking information and statements contained in this news release speak only as of the date of this news 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 news release contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook 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. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein. 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 dated March 13, 2009 for the year ended December 31, 2008, a copy of which is available on the Fund's SEDAR profile at and which also forms part of the Fund's annual report on Form 40-F for the year ended December 31, 2008 filed with the United States Securities and Exchange Commission, a copy of which is available at For a description of Enerplus' Marcellus shale gas properties including the primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Marcellus properties as reserves and the inherent risks and contingencies associated with the resource estimates and development of the project, see Enerplus' final short form prospectus dated September 1, 2009, a copy of which is available on the Fund's SEDAR profile at

%CIK: 0001126874

For further information: please contact our Investor Relations Department at 1-800-319-6462 or email

(53 KB)


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