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News Releases

Enerplus reports third quarter results for 2009

November 13, 2009

CALGARY, Nov. 13 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) announces operating and financial results for the third quarter of 2009 that continue to meet or exceed our operating targets, execute on our growth strategies and maintain our balance sheet strength. Full copies of our third quarter 2009 Financial Statements and MD&A have been filed on our website at, under our profile on SEDAR at, and on the EDGAR website at



    -   Daily production averaged 90,111 BOE/day during the quarter and
        93,184 BOE/day year-to-date. We continue to expect 2009 annual
        production volumes to average 91,000 BOE/day.

    -   Cash flow from operations was $207.2 million, comparable to that of
        the second quarter of 2009. Approximately 45% of our cash flow was
        distributed to our unitholders with monthly cash distributions of
        $0.18/unit maintained throughout the quarter. When combining
        distributions and capital spending during the quarter, our adjusted
        payout ratio was 68%. Year-to-date, our adjusted payout ratio has
        averaged 78%, however, given the high level of capital spending
        planned for the fourth quarter of 2009, we expect our adjusted payout
        ratio to be approximately 100% for the entire year.

    -   Capital expenditures totaled $45.4 million during the quarter with
        48 gross wells drilled (27.6 net wells). Our year-to-date capital
        spending has totaled $180.2 million with 229 gross wells drilled
        (156.6 net wells). Our drilling success rate was 99%.

    -   We have actively been working to control costs throughout 2009 and
        our efforts have resulted in operating costs of $10.07/BOE for the
        third quarter and an average of $9.94/BOE for the year. Based on
        these results, we are lowering our full year guidance from
        $10.65/BOE to $10.20/BOE, an improvement of over 4% from our
        original target. Our general and administrative costs remain on track
        to meet our full year guidance of $2.45/BOE.

    -   Our hedging program realized cash gains of $40.6 million in the
        quarter, helping to offset weak natural gas prices. Year-to-date, we
        have realized cash hedging gains totaling $129.1 million.


    -   We completed our first significant transaction in the U.S. shale gas
        plays acquiring an average 21.5% working interest in over
        540,000 gross acres of land in the Marcellus shale region in
        northeast United States from Chief Oil & Gas LLC and certain
        affiliated entities ("Chief"). Total consideration for this interest
        was approximately US$411 million, consisting of an upfront cash
        payment of US$164 million that was paid upon closing and US$247
        million to be paid as a carry of 50% of Chief's future drilling and
        completion costs in the Marcellus shale play which we expect will be
        invested over the next four years. Our net production at the time of
        the transaction was approximately 1.8 MMcfe/day, with a line of
        sight to approximately 100 MMcfe/day within the next five years. Our
        internal assessment has identified over 1.4 trillion cubic feet of
        best estimate contingent resources on these lands, net to Enerplus,
        which would almost double our proved plus probable natural gas
        reserves currently booked. See "Information Regarding Contingent
        Resource Estimates" at the end of this news release.

    -   Subsequent to quarter end, we purchased a 50% non-operated working
        interest in over 22,000 gross acres of prospective Bakken land in
        North Dakota for US$27 million, consisting of US$15 million in cash
        and US$12 million of carry capital to be invested over the next
        12 months. We have assessed an internal best estimate of contingent
        resources on this acreage of approximately 7.4 million barrels, net
        to Enerplus, based upon a 13% recovery factor.

    -   We sold approximately 4.5 net sections of low working interest,
        non-core property interests in southeast Saskatchewan for
        approximately $100 million subsequent to the quarter. These lands
        were producing approximately 200 BOE/day of oil with 1.5 million BOE
        of booked proved plus probable reserves. We continue to prepare to
        sell non-core oil and gas assets that will allow us to focus our
        efforts and capital on existing core resource plays and expand our
        interests in targeted resource plays. We expect to have completed
        this work and to be in a position for sale in 2010.


    -   In September we completed an equity financing issuing approximately
        10 million trust units at $21.65 per unit for gross proceeds of
        $225 million. The proceeds of this financing were used to fund the
        upfront costs of the Marcellus acquisition, with the balance used to
        reduce outstanding bank debt to zero at the end of the quarter.

    -   We currently have the full $1.4 billion of bank credit capacity
        available and our balance sheet remains strong with a debt to
        trailing 12 month cash flow ratio of 0.7x.


                                Three months ended         Nine months ended
                                    September 30,             September 30,
    (in Canadian dollars)        2009         2008         2009         2008
    Financial (000's)
      Cash Flow from
       Operating Activities  $207,211     $383,573     $587,207   $1,004,246
      Cash Distributions to
       Unitholders(1)          93,504      224,417      272,651      619,121
      Excess of Cash Flow
       Over Cash
       Distributions          113,707      159,156      314,556      385,125
      Net Income               38,182      465,773       86,399      699,397
      Debt Outstanding -
       net of cash            561,218      522,254      561,218      522,254
      Development Capital
       Spending                45,417      163,215      180,222      377,485
      Acquisitions            192,484        4,574      222,877    1,771,383
      Divestments                 519      502,489        2,255      504,697

    Actual Cash Distributions
     paid to Unitholders        $0.54        $1.31        $1.69        $3.83

    Financial per Weighted
     Average Trust Units(2)
      Cash Flow from
       Operating Activities     $1.23        $2.33        $3.52        $6.32
      Cash Distributions per
       Unit(1)                   0.55         1.36         1.63         3.89
      Excess of Cash Flow
       Over Cash
       Distributions             0.68         0.97         1.89         2.42
      Net Income                 0.23         2.82         0.52         4.40
      Payout Ratio(3)             45%          59%          46%          62%
      Adjusted Payout
       Ratio(3)                   68%         102%          78%         100%

    Selected Financial
     Results per BOE(4)
      Oil & Gas Sales(5)       $35.23       $73.62       $35.36       $72.44
      Royalties                 (5.56)      (13.71)       (6.10)      (13.54)
      Commodity Derivative
       Instruments               4.89        (6.82)        5.08        (5.19)
      Operating Costs          (10.00)      (10.10)       (9.84)       (9.51)
      General and
       Administrative           (2.21)       (1.50)       (2.18)       (1.66)
      Interest and Other
       Income and Foreign
       Exchange                 (0.79)       (1.46)       (0.22)       (1.23)
      Taxes                     (0.35)       (0.59)       (0.22)       (1.19)
      Asset Retirement
       Obligations Settled      (0.31)       (0.54)       (0.34)       (0.52)
    Cash Flow from Operating
     Activities before
     changes in non-cash
     working capital           $20.90       $38.90       $21.54       $39.60

    Weighted Average Number
     of Trust Units
     Outstanding(2)           168,521      164,908      166,724      158,980
    Debt to Trailing Twelve
     Month Cash Flow Ratio(6)    0.7x         0.4x         0.7x         0.4x


                                Three months ended         Nine months ended
                                   September 30,             September 30,
                                 2009         2008         2009         2008
    Average Daily Production
      Natural gas (Mcf/day)   323,884      341,803      333,606      336,328
      Crude oil (bbls/day)     32,218       34,119       33,454       34,295
      Natural gas liquids
       (bbls/day)               3,912        4,557        4,129        4,660
      Total daily sales
       (BOE/day)               90,111       95,644       93,184       95,010

      % Natural gas               60%          60%          60%          59%

    Average Selling Price(5)
      Natural gas (per Mcf)     $2.95        $8.25        $3.86        $8.60
      Crude oil (per bbl)       64.94       110.63        55.57       103.85
      NGLs (per bbl)            32.59        81.20        36.21        77.21
      CDN$/US$ exchange rate     0.91         0.96         0.85         0.98

    Net Wells drilled            27.6          272        156.6          469
    Success Rate(7)              100%          99%          99%          99%
    (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" at the conclusion of this news
    (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
    (7) Based on wells drilled and cased.


    For the three months ended        TSX - ERF.un             U.S.* - ERF
     September 30, 2009                      (CDN$)                     (US$)
    High                                    $24.82                    $23.18
    Low                                     $21.28                    $18.23
    Close                                   $24.50                    $22.89
    * U.S. Composite Exchange Data including NYSE.


    Payment Month                             CDN$                       US$
    First Quarter Total                      $0.61                     $0.49
    Second Quarter Total                     $0.54                     $0.47

    July                                     $0.18                     $0.16
    August                                    0.18                      0.16
    September                                 0.18                      0.17
    Third Quarter Total                      $0.54                     $0.49

    Total Year-to-Date                       $1.69                     $1.45


    Our development capital spending continues to reflect the prudent approach
we undertook at the start of 2009 in light of commodity price uncertainty and
a focus on achieving compelling returns on our investment. Our activities in
the first half of 2009 were focused on natural gas drilling in our shallow gas
and tight gas resource plays. As the price of natural gas continued to
deteriorate throughout the year and oil prices strengthened, we began shifting
our development program. This shift resulted in a low level of spending in the
third quarter and set up a high activity level for the fourth quarter. We
expect to focus on oil projects on our Bakken lands and waterflood assets and
are limiting our natural gas activities primarily to the Marcellus and
utilizing the Alberta Drilling Royalty Credit ("DRC") incentive. As we
participate in more early stage growth plays, we anticipate increasing our
land and seismic expenditures in key areas. We continue to maintain our
capital guidance of $330 million for 2009 including our carry obligations
associated with the Marcellus shale gas play and which is net of the credits
associated with the DRC incentive, with fourth quarter spending up
significantly over the previous quarters of 2009.


                                 Three months ended September 30, 2009
                           Production      Capital        Wells Drilled
                              Volumes     Spending  -------------------------
    Play Type                (BOE/day) ($ millions) Total Gross    Total Net
    Shallow Gas                22,478          9.1           22           21
    Crude Oil Waterfloods      15,703          8.5            1            1
    Tight Gas                  15,310          9.7            1          0.1
    Bakken/Tight Oil            9,756          9.3           10            2
    Conventional Oil & Gas     26,766          4.3           11            3
    Shale Gas*                   98          3.1            3          0.5
    Total Conventional         90,111         44.0           48         27.6

    Oil Sands                       -          1.4            -            -
    Total                      90,111         45.4           48         27.6
    * The Marcellus shale gas acquisition closed September 1, 2009.

                                 Nine months ended September 30, 2009
                           Production      Capital        Wells Drilled
                              Volumes     Spending  -------------------------
    Play Type                (BOE/day) ($ millions) Total Gross    Total Net
    Shallow Gas                23,504         38.7          143          126
    Crude Oil Waterfloods      16,007         22.0            3            2
    Tight Gas                  15,689         45.0           21         11.1
    Bakken/Tight Oil           10,350         26.8           12            3
    Conventional Oil & Gas     27,601         30.0           47           14
    Shale Gas*                   33          3.1            3          0.5
    Total Conventional         93,184        165.6          229        156.6

    Oil Sands                       -         14.6            -            -
    Total                      93,184        180.2          229        156.6
    * The Marcellus shale gas acquisition closed September 1, 2009.


Shallow Gas and DRC Incentives


We remain active in our shallow gas resource play but due to weak natural gas prices we drilled only a modest number of wells (12) in the third quarter to complete our activities at Shackleton for the year, and have elected not to tie these wells in until gas prices recover. However, we started drilling the first nine of approximately 250 shallow gas wells in Alberta to take advantage of the DRC incentive. This incentive offers a drilling credit of $200 for every metre drilled, allowing us to substantially recover the cost of drilling a shallow gas well. We plan to utilize the benefits of this program primarily at Verger, Bantry, Hanna Garden and Princess. Most of the drilling activity is expected to occur in the fourth quarter of 2009 however we expect to complete and tie in wells as economic conditions warrant. As a result, the benefit of new production volumes associated with this drilling are not anticipated until 2010. We also plan on drilling approximately 15 oil wells under the DRC program at various locations throughout Alberta late this year or early 2010. Based on drilling plans for the fourth quarter, we are estimating a recovery of approximately $22 million from the DRC program in the current year.


Marcellus Shale Gas


Capital spending in our Marcellus shale gas play is expected to be approximately $40 million in 2009, up from our original estimate of $30 million. This spending will consist of approximately $20 million in drilling capital, $5 million in land and seismic, and $15 million of carry obligations mentioned previously. A total of 39 wells have now been drilled to date on our Marcellus lands, comprised of 28 horizontal wells and 11 vertical wells. Eight of these wells have been drilled since we acquired our interest in September. Currently 20 horizontal wells are waiting on completion and 7 horizontal wells are being drilled or remain to be drilled in 2009. Given encouraging results to date, we are adding a fourth rig and expect 2010 capital expenditures to exceed our initial estimates. Activities have been focused on testing new areas and drilling and completion methods to identify the optimal approach. We expect to move to pad drilling this winter in several areas which have been derisked by offset wells. Chief Gathering LLC, the midstream subsidiary of Chief Oil & Gas, continues to progress with the construction of its pipeline infrastructure. Chief Gathering has secured seven interstate pipeline interconnects: two each in Lycoming and Fayette counties and one each in Bradford, Susquehanna and Clearfield counties. We expect to provide a more detailed update on drilling results and capital plans, as part of our 2010 guidance announcement planned for mid-December. Current production is approximately 10 MMcfe/day gross (2.1 MMcfe/day net to Enerplus) from 11 producing wells of which 6 are horizontal and 5 vertical.


Bakken/Tight Oil


The improvement in crude oil prices has also resulted in increased activity in our Bakken/Tight Oil assets. At Sleeping Giant, we are resuming our drilling activity and have increased our refrac program to 18 refracs for the year. We plan to utilize tri-fracs (three wells frac'd simultaneously) to complete the program. Twelve refracs had been completed at the end of the third quarter. This activity continues to yield positive results with production gains of approximately 50 BOE/day gross (35 BOE/day net) per refrac and expected reserve additions of approximately 50 MBOE gross (35 MBOE net). We have contracted two rigs and plan to drill four wells at Sleeping Giant by year end. We estimate at year end we will have eight third well and 40 lease line drilling opportunities remaining on our lands as well as approximately 100 refracs in our inventory. We also plan to continue drilling at Taylorton in southern Saskatchewan where we participated in the drilling of 5 gross wells (1.25 net wells) in the third quarter and have another three gross wells (0.75 net wells) planned with our partner for the fourth quarter. On our newly acquired North Dakota acreage, initial plans include four gross wells (two net wells) drilled in late 2009 or early 2010. Although this is a non-operated position for Enerplus, due to our considerable drilling expertise in the Bakken, Enerplus will operate the drilling activities. Additionally, we are drilling on our operated Bakken lands in other areas as part of our overall Bakken portfolio.


Waterfloods and Other Oil


Drilling activity is also expected to increase on our crude oil waterflood properties in the fourth quarter. We currently have development plans at Virden, Manitoba and the Glauconitic "C" unit at Medicine Hat in Alberta, and at our Freda Lake waterflood in Saskatchewan. A total of 11 gross wells are planned in these areas, all of which will be horizontal wells. The current moratorium on licensing any wells with H2S in Alberta may slow our plans. We are also increasing our conventional oil activities on select fields primarily in southeast Saskatchewan and plan to drill approximately three wells in the fourth quarter.




Looking ahead, our business strategy is clear. We believe a balance of growth and income will provide a compelling investment opportunity and the addition of more early stage resource play assets to our portfolio of core cash flow generating assets will help us to achieve this. We expect these early stage assets to be focused on tight gas and tight oil that we believe will deliver top quartile economics. We plan to utilize our balance sheet strength prudently to acquire additional assets and to help fund the capital needs of these growth plays. We also remain focused on the successful execution of our operational plans, maintaining the discipline we apply to our spending and improving the efficiencies of our day-to-day business.




Third quarter 2009 Consolidated Financial Statements and Notes to the Consolidated Financial Statements, along with the Management's Discussion and Analysis for Enerplus have been filed on our website at, under our profile on SEDAR ( and on the EDGAR website at




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. "MMcfe" means million cubic feet of gas equivalent. Enerplus has adopted the standard of one barrel of oil to six thousand cubic feet of gas (1 barrel: 6 Mcf) when converting oil to MMcfes. MMcfes may be misleading, particularly if used in isolation. An MMcfe conversion ratio of 1 barrel: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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.




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 drilling plans 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; and future dispositions of oil and gas assets. 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 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

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.




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 Gs 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. The contingent resource estimate for the acquired interests in the Marcellus properties set forth in this news release is presented as Enerplus' internal "best estimate" of the quantity that will actually be recovered effective as of July 1, 2009, and the contingent resource estimate for the acquired interests in the Bakken properties set forth in this news release is presented as Enerplus' internal "best estimate" of the quantity that will actually be recovered effective as of July 1, 2009. 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 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. The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Marcellus and Bakken properties as "reserves" consist of: additional delineation drilling to establish economic productivity in the development areas, limitations to development based on adverse topography or other surface restrictions (primarily Marcellus), the uncertainty regarding marketing and transportation of natural gas from development areas, the receipt of all required regulatory permits and approvals to develop the lands, and access to confidential information of other operators in the area. Significant negative factors related to the estimate include: the pace of development, including drilling and infrastructure, is slower than the forecast, risk of adverse regulatory and tax changes, ongoing litigation related to minimum royalties payable to freehold landowners, and other issues related to oil and gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of the acquired interests in the Marcellus and Bakken properties, including commodity price fluctuations, project costs, Enerplus' ability to make the necessary capital expenditures to develop the properties, reliance on Enerplus' industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described under "Risk Factors" in our annual information form for the year ended December 31, 2008, a copy of which is available on our SEDAR profile at and on our website at, and which forms part of our annual report on Form 40-F filed with the U.S. Securities and Exchange Commission at




Throughout this news release 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.


Gordon J. Kerr

President & Chief Executive Officer

Enerplus Resources Fund


%CIK: 0001126874

For further information: regarding this news release or a copy of our 2009 third quarter interim report, please contact our investor relations department at 1-800-319-6462 or email

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